Edgar Filing: DYNEGY INC.

June 30,

2007

December 31,
2006

(in millions)

One Day VaR—95% Confidence Level

One Day VaR—99% Confidence Level

Average VaR for the Year-to-Date Period—95% Confidence Level

Form 10-Q for quarterly period ended June 30, 2007

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2007

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

DYNEGY INC.

DYNEGY HOLDINGS INC.

(Exact name of registrant as specified in its charter)


Entity	Commission File Number	State of Incorporation	I.R.S. Employer Identification No.
Dynegy Inc.	001-33443	Delaware	20-5653152
Dynegy Holdings Inc.	000-29311	Delaware	94-3248415

1000 Louisiana, Suite 5800

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)

(713) 507-6400

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.


Dynegy Inc.		Yes x No ¨
Dynegy Holdings Inc.		Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.


	Large accelerated filer	Accelerated filer	Non-accelerated filer
Dynegy Inc.	x	¨	¨
Dynegy Holdings Inc.	¨	¨	x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).


Dynegy Inc.		Yes ¨ No x
Dynegy Holdings Inc.		Yes ¨ No x

Indicate the number of shares outstanding of Dynegy Inc.’s classes of common stock, as of the latest practicable date: Class A common stock, $0.01 par value per share, 499,962,177 shares outstanding as of August 2, 2007; Class B common stock, $0.01 par value per share, 340,000,000 shares outstanding as of August 2, 2007. All of Dynegy Holdings Inc.’s outstanding common stock is owned indirectly by Dynegy Inc.

This combined Form 10-Q is separately filed by Dynegy Inc. and Dynegy Holdings Inc. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to a registrant other than itself.

DYNEGY INC. and DYNEGY HOLDINGS INC.

TABLE OF CONTENTS


		Page
PART I. FINANCIAL INFORMATION

	Item 1. FINANCIAL STATEMENTS—DYNEGY INC. AND DYNEGY HOLDINGS INC.:

	Condensed Consolidated Balance Sheets—Dynegy Inc.: June 30, 2007 and December 31, 2006	5
	Condensed Consolidated Statements of Operations—Dynegy Inc.: For the three and six months ended June 30, 2007 and 2006	6
	Condensed Consolidated Statements of Cash Flows—Dynegy Inc.: For the six months ended June 30, 2007 and 2006	7
	Condensed Consolidated Statements of Comprehensive Income (Loss) —Dynegy Inc.: For the three and six months ended June 30, 2007 and 2006	8
	Condensed Consolidated Balance Sheets—Dynegy Holdings Inc.: June 30, 2007 and December 31, 2006	9
	Condensed Consolidated Statements of Operations—Dynegy Holdings Inc.: For the three and six months ended June 30, 2007 and 2006	10
	Condensed Consolidated Statements of Cash Flows—Dynegy Holdings Inc.: For the six months ended June 30, 2007 and 2006	11
	Condensed Consolidated Statements of Comprehensive Income (Loss) —Dynegy Holdings Inc.: For the three and six months ended June 30, 2007 and 2006	12
	Notes to Condensed Consolidated Financial Statements	13

	Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—DYNEGY INC. AND DYNEGY HOLDINGS INC.	49
	Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK—DYNEGY INC. AND DYNEGY HOLDINGS INC.	84
	Item 4. CONTROLS AND PROCEDURES—DYNEGY INC. AND DYNEGY HOLDINGS INC.	86

PART II. OTHER INFORMATION

	Item 1. LEGAL PROCEEDINGS—DYNEGY INC. AND DYNEGY HOLDINGS INC.	87
	Item 1A RISK FACTORS—DYNEGY INC. AND DYNEGY HOLDINGS INC.	87
	Item 2. UNREGISTERED SALES OF SECURITIES AND USE OF PROCEEDS—DYNEGY INC.	88
	Item 6. EXHIBITS—DYNEGY INC. AND DYNEGY HOLDINGS INC.	88

EXPLANATORY NOTE

Dynegy Inc. (“Dynegy”) is a Delaware corporation formerly named Dynegy Acquisition, Inc. Dynegy entered into a Plan of Merger, Contribution and Sale Agreement (the “Merger Agreement”), dated as of September 14, 2006, with Falcon Merger Sub Co., an Illinois corporation (“Merger Sub”), LSP Gen Investors, L.P., a Delaware limited partnership, LS Power Partners, L.P., a Delaware limited partnership, LS Power Equity Partners PIE I, L.P., a Delaware limited partnership, LS Power Equity Partners, L.P., a Delaware limited partnership, LS Power Associates, L.P., a Delaware limited partnership, and Dynegy Illinois Inc., an Illinois corporation (formerly named Dynegy Inc.) (“Dynegy Illinois”). On March 29, 2007, at a special meeting of the shareholders of Dynegy Illinois, the shareholders of Dynegy Illinois adopted the Merger Agreement and approved the related merger of Merger Sub, Dynegy’s then wholly owned subsidiary, with and into Dynegy Illinois (the “Merger”).

As a result of the Merger, which was completed on April 2, 2007, Dynegy Illinois became Dynegy’s wholly owned subsidiary, the then-shareholders of Dynegy Illinois became Dynegy’s stockholders and each Dynegy Illinois shareholder received one share of Dynegy’s Class A common stock for each share of Class A common stock or Class B common stock of Dynegy Illinois held by it. In addition, in connection with the completion of the Merger and the other transactions contemplated by the Merger Agreement, Dynegy Acquisition, Inc. changed its name to Dynegy Inc. Dynegy is a “successor registrant” to Dynegy Illinois for purposes of the Securities Act of 1933, as amended, and the Securities Exchange Act of 1934, as amended, and the rules and regulations of the Securities and Exchange Commission promulgated thereunder.

This report includes the combined filing of Dynegy and Dynegy Holdings Inc. (“DHI”). DHI is the principal subsidiary of Dynegy, providing approximately 100% of Dynegy’s total consolidated revenue for the six-month period ended June 30, 2007 and constituting approximately 100% of Dynegy’s total consolidated asset base as of June 30, 2007 except for Dynegy’s 50% interest in DLS Power Holdings, LLC and DLS Power Development Company, LLC. Unless the context indicates otherwise, throughout this report, the terms “the Company”, “we”, “us”, “our” and “ours” are used to refer to both Dynegy and DHI and their direct and indirect subsidiaries, including Dynegy Illinois before it became a wholly owned subsidiary of Dynegy by way of the Merger. Discussions or areas of this report that apply only to Dynegy or DHI will clearly be noted in such section. Historically, Dynegy and DHI have filed separate SEC filings. Beginning with this Form 10-Q for the quarterly period ended June 30, 2007 and in the future, Dynegy and DHI intend to file combined periodic reports on an interim and annual basis as permitted by applicable SEC rules and regulations.

DEFINITIONS

As used in this Form 10-Q, the abbreviations contained herein have the meanings set forth below.


APB		Accounting Principles Board
ARO		Asset retirement obligation
Cal ISO		The California Independent System Operator
CARB		California Air Resources Board
CDWR		California Department of Water Resources
CEC		California Energy Commission
CFTC		Commodity Futures Trading Commission
CO₂		Carbon Dioxide
CPUC		California Public Utilities Commission
CRA		Canada Revenue Agency
CRM		Our customer risk management business segment
CUSA		Chevron U.S.A. Inc., a wholly owned subsidiary of Chevron Corporation
DGC		Dynegy Global Communications
DHI		Dynegy Holdings Inc., Dynegy’s primary financing subsidiary
DMG		Dynegy Midwest Generation, Inc.
DMSLP		Dynegy Midstream Services L.P.
DMT		Dynegy Marketing and Trade
DNE		Dynegy Northeast Generation
DPM		Dynegy Power Marketing Inc.
EBITDA		Earnings Before Interest, Taxes, Depreciation and Amortization
EITF		Emerging Issues Task Force
EMA		Energy management agreement
EPA		Environmental Protection Agency
ERCOT		Electric Reliability Council of Texas, Inc.
ERISA		The Employee Retirement Income Security Act of 1974, as amended
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FIN		FASB Interpretation
FSP		FASB Staff Position
GAAP		Generally Accepted Accounting Principles of the United States of America
GEN		Our power generation business
GEN-MW		Our power generation business - Midwest segment
GEN-NE		Our power generation business - Northeast segment
GEN-SO		Our power generation business - South segment, which was renamed GEN-WE
GEN-WE		Our power generation business - West segment
ICC		Illinois Commerce Commission
IRS		Internal Revenue Service
ISO		Independent System Operator
LNG		Liquefied natural gas
LTSA		Long term service agreement
MISO		Midwest Independent Transmission Operator, Inc.
MMBtu		Millions of British thermal units
MW		Megawatts
MWh		Megawatt hour
NGL		Our former natural gas liquids business segment
NNG		Northern Natural Gas Company
NOL		Net operating loss
NO_x		Nitrogen Oxide
NRG		NRG Energy, Inc.
NYSDEC		New York State Department of Environmental Conservation
PRB		Powder River Basin coal
PUHCA		Public Utility Holding Company Act of 1935, as amended
SAB		SEC Staff Accounting Bulletin
SEC		U.S. Securities and Exchange Commission
SFAS		Statement of Financial Accounting Standards
SPN		Second Priority Senior Secured Notes
VaR		Value at Risk
VIE		Variable Interest Entity

PART I. FINANCIAL INFORMATION

Item 1—FINANCIAL STATEMENTS—DYNEGY INC. AND DYNEGY HOLDINGS INC.

DYNEGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions, except share data)


	June 30, 2007			December 31, 2006
ASSETS
Current Assets
Cash and cash equivalents	$	323		$	371
Restricted cash		124			280
Accounts receivable, net of allowance for doubtful accounts of $22 and $48, respectively		431			257
Accounts receivable, affiliates		—			1
Inventory		193			194
Assets from risk-management activities		433			701
Deferred income taxes		114			93
Prepayments and other current assets		134			92
Assets held for sale (Note 3)		272			—

Total Current Assets		2,024			1,989

Property, Plant and Equipment		10,486			6,473
Accumulated depreciation		(1,513	)		(1,522	)

Property, Plant and Equipment, Net		8,973			4,951
Other Assets
Unconsolidated investments		86			—
Restricted cash and investments		912			83
Assets from risk-management activities		149			16
Goodwill		590			—
Intangible assets		337			347
Deferred income taxes		4			12
Other long-term assets		193			139
Assets held for sale (Note 3)		56			—

Total Assets	$	13,324		$	7,537

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	330		$	172
Accrued interest		85			66
Accrued liabilities and other current liabilities		227			231
Liabilities from risk-management activities		414			629
Notes payable and current portion of long-term debt		54			68
Liabilities held for sale (Note 3)		20			—

Total Current Liabilities		1,130			1,166

Long-term debt		5,940			2,990
Long-term debt, affiliates		200			200

Long-Term Debt		6,140			3,190
Other Liabilities
Liabilities from risk-management activities		193			35
Deferred income taxes		1,105			469
Other long-term liabilities		449			410
Liabilities held for sale (Note 3)		1			—

Total Liabilities		9,018			5,270

Minority Interest		(16	)		—
Commitments and Contingencies (Note 10)
Stockholders’ Equity
Class A Common Stock, $0.01 par value, 2,100,000,000 shares authorized at June 30, 2007; 502,373,963 shares issued and outstanding at June 30, 2007; and no par value, 900,000,000 shares authorized at December 31, 2006; 403,137,339 shares issued and outstanding at December 31, 2006		5			3,367
Class B Common Stock, $0.01 par value, 850,000,000 shares authorized at June 30, 2007; 340,000,000 shares issued and outstanding at June 30, 2007; and no par value, 360,000,000 shares authorized at December 31, 2006; 96,891,014 shares issued and outstanding at December 31, 2006		3			1,006
Additional paid-in capital		6,449			39
Subscriptions receivable		(8	)		(8	)
Accumulated other comprehensive income (loss), net of tax		(18	)		67
Accumulated deficit		(2,038	)		(2,135	)
Treasury stock, at cost, 2,445,986 shares at June 30, 2007 and 1,787,004 shares at December 31, 2006, respectively		(71	)		(69	)

Total Stockholders’ Equity		4,322			2,267

Total Liabilities and Stockholders’ Equity	$	13,324		$	7,537

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited) (in millions, except per share data)


	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
Revenues	$	828		$	379		$	1,333		$	919
Cost of sales, exclusive of depreciation shown separately below		(510	)		(249	)		(829	)		(588	)
Depreciation and amortization expense		(88	)		(54	)		(140	)		(110	)
Impairment and other charges		—			(9	)		—			(11	)
Gain on sale of assets, net		—			3			—			3
General and administrative expenses		(48	)		(50	)		(101	)		(101	)

Operating income		182			20			263			112
Earnings (losses) from unconsolidated investments		(2	)		—			(2	)		2
Interest expense		(84	)		(107	)		(151	)		(205	)
Debt conversion costs		—			(247	)		—			(247	)
Minority interest expense		(9	)		—			(9	)		—
Other income and expense, net		10			10			18			30

Income (loss) from continuing operations before income taxes		97			(324	)		119			(308	)
Income tax (expense) benefit (Note 13)		(30	)		117			(36	)		109

Income (loss) from continuing operations		67			(207	)		83			(199	)
Income (loss) from discontinued operations, net of tax (expense) benefit of $(5), $3, $(4) and $7, respectively (Notes 3 and 13)		9			—			7			(8	)

Income (loss) before cumulative effect of change in accounting principle		76			(207	)		90			(207	)
Cumulative effect of change in accounting principle, net of tax expense of zero		—			—			—			1

Net income (loss)		76			(207	)		90			(206	)
Less: preferred stock dividends		—			4			—			9

Net income (loss) applicable to common stockholders	$	76		$	(211	)	$	90		$	(215	)

Earnings (Loss) Per Share (Note 9):
Basic earnings (loss) per share:
Income (loss) from continuing operations	$	0.08		$	(0.48	)	$	0.13		$	(0.49	)
Income (loss) from discontinued operations		0.01			—			0.01			(0.02	)
Cumulative effect of change in accounting principle		—			—			—			—

Basic earnings (loss) per share	$	0.09		$	(0.48	)	$	0.14		$	(0.51	)

Diluted earnings (loss) per share:
Income (loss) from continuing operations	$	0.08		$	(0.48	)	$	0.12		$	(0.49	)
Income (loss) from discontinued operations		0.01			—			0.01			(0.02	)
Cumulative effect of change in accounting principle		—			—			—			—

Diluted earnings (loss) per share	$	0.09		$	(0.48	)	$	0.13		$	(0.51	)

Basic shares outstanding		828			442			663			421
Diluted shares outstanding		830			513			665			519

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)


	Six Months Ended June 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	90		$	(206	)
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation and amortization		146			148
Impairment and other charges		—			11
Earnings from unconsolidated investments, net of cash distributions		2			(2	)
Risk-management activities		(97	)		(52	)
Gain on sale of assets, net		—			(4	)
Deferred income taxes		41			(119	)
Cumulative effect of change in accounting principle, net of tax		—			(1	)
Legal and settlement charges		11			23
Debt conversion charges		—			247
Other		10			32
Changes in working capital:
Accounts receivable		(130	)		294
Inventory		(3	)		4
Prepayments and other assets		(18	)		79
Accounts payable and accrued liabilities		119			(819	)
Changes in non-current assets		(17	)		(6	)
Changes in non-current liabilities		3			3

Net cash provided by (used in) operating activities		157			(368	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(153	)		(59	)
Unconsolidated investments		(5	)		—
Proceeds from asset sales, net		—			6
Business acquisitions, net of cash acquired		(126	)		—
Net proceeds from exchange of unconsolidated investments, net of cash acquired		—			165
Decrease (increase) in restricted cash and restricted investments		(589	)		162
Other investing		—			(3	)

Net cash provided by (used in) investing activities		(873	)		271

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net		2,663			1,071
Repayments of long-term borrowings		(1,994	)		(1,683	)
Debt conversion costs		—			(247	)
Redemption of Series C Preferred		—			(400	)
Proceeds from issuance of capital stock		1			182
Dividends and other distributions, net		—			(17	)
Other financing, net		(2	)		—

Net cash provided by (used in) financing activities		668			(1,094	)

Net decrease in cash and cash equivalents		(48	)		(1,191	)
Cash and cash equivalents, beginning of period		371			1,549

Cash and cash equivalents, end of period	$	323		$	358

Other non-cash financing activity:
Conversion of Convertible Subordinated Debentures due 2023	$	—		$	225

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited) (in millions)


	Three Months Ended June 30,
	2007			2006
Net income (loss)	$	76		$	(207	)
Cash flow hedging activities, net:
Unrealized mark-to-market gains arising during period, net		—			12
Reclassification of mark-to-market gains to earnings, net		(13	)		(3	)

Changes in cash flow hedging activities, net (net of tax benefit (expense) of $8 and ($5), respectively)		(13	)		9
Recognized prior service cost and actuarial loss		1			—
Unrealized loss on securities, net of tax benefit of $1		(2	)		—
Foreign currency translation adjustment		2			3

Other comprehensive income (loss), net of tax		(12	)		12

Comprehensive income (loss)	$	64		$	(195	)


	Six Months Ended June 30,
	2007			2006
Net income (loss)	$	90		$	(206	)
Cash flow hedging activities, net:
Unrealized mark-to-market gains (losses) arising during period, net		(59	)		25
Reclassification of mark-to-market (gains) losses to earnings, net		(28	)		(12	)

Changes in cash flow hedging activities, net (net of tax benefit (expense) of $51 and ($8), respectively)		(87	)		13
Recognized prior service cost and actuarial loss		2			—
Unrealized loss on securities, net of tax benefit of $1		(2	)		—
Foreign currency translation adjustment		2			3

Other comprehensive income (loss), net of tax		(85	)		16

Comprehensive income (loss)	$	5		$	(190	)

See the notes to condensed consolidated financial statements.

DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions)


	June 30, 2007			December 31, 2006
ASSETS
Current Assets
Cash and cash equivalents	$	280		$	243
Restricted cash		124			280
Accounts receivable, net of allowance for doubtful accounts of $22 and $46 respectively		437			263
Accounts receivable, affiliates		—			7
Inventory		193			194
Assets from risk-management activities		433			701
Deferred income taxes		46			48
Prepayments and other current assets		134			92
Assets held for sale (Note 3)		272			—

Total Current Assets		1,919			1,828

Property, Plant and Equipment		10,486			6,473
Accumulated depreciation		(1,513	)		(1,522	)

Property, Plant and Equipment, Net		8,973			4,951
Other Assets
Restricted cash and investments		912			83
Assets from risk-management activities		149			16
Long-term accounts receivable, affiliate		797			781
Goodwill		590			—
Intangible assets		337			347
Deferred income taxes		4			12
Other long-term assets		182			118
Assets held for sale (Note 3)		56			—

Total Assets	$	13,919		$	8,136

LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities
Accounts payable	$	330		$	172
Accrued interest		85			66
Accrued liabilities and other current liabilities		227			230
Liabilities from risk-management activities		414			629
Notes payable and current portion of long-term debt		54			68
Liabilities held for sale (Note 3)		20			—

Total Current Liabilities		1,130			1,165

Long-term debt		5,940			2,990
Long-term debt to affiliates		200			200

Long-Term Debt		6,140			3,190
Other Liabilities
Liabilities from risk-management activities		193			35
Deferred income taxes		841			325
Other long-term liabilities		428			385
Liabilities held for sale (Note 3)		1			—

Total Liabilities		8,733			5,100

Minority Interest		(16	)		—
Commitments and Contingencies (Note 10)
Stockholder’s Equity
Capital Stock, $1 par value, 1,000 shares authorized at June 30, 2007 and December 31, 2006, respectively		—			—
Additional paid-in capital		4,637			2,511
Accumulated other comprehensive income (loss), net of tax		(18	)		67
Accumulated deficit		(449	)		(574	)
Stockholder’s equity		1,032			1,032

Total Stockholder’s Equity		5,202			3,036

Total Liabilities and Stockholder’s Equity	$	13,919		$	8,136

See the notes to condensed consolidated financial statements.

DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited) (in millions)


	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
Revenues	$	828		$	379		$	1,333		$	919
Cost of sales, exclusive of depreciation shown separately below		(510	)		(249	)		(829	)		(588	)
Depreciation and amortization expense		(88	)		(54	)		(140	)		(110	)
Impairment and other charges		—			(9	)		—			(11	)
Gain on sale of assets, net		—			3			—			3
General and administrative expenses		(46	)		(49	)		(82	)		(100	)

Operating income		184			21			282			113
Earnings from unconsolidated investments		—			—			—			2
Interest expense		(84	)		(103	)		(151	)		(198	)
Debt conversion costs		—			(202	)		—			(202	)
Minority interest expense		(9	)		—			(9	)		—
Other income and expense, net		12			10			16			27

Income (loss) from continuing operations before income taxes		103			(274	)		138			(258	)
Income tax (expense) benefit (Note 13)		(21	)		94			(32	)		89

Income (loss) from continuing operations		82			(180	)		106			(169	)
Income (loss) from discontinued operations, net of tax (expense) benefit of $(6), $2, $(5) and $6, respectively (Notes 3 and 13)		8			(1	)		6			(9	)

Net income (loss)	$	90		$	(181	)	$	112		$	(178	)

See the notes to condensed consolidated financial statements.

DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)


	Six Months Ended June 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	112		$	(178	)
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation and amortization		146			146
Impairment and other charges		—			11
Earnings from unconsolidated investments, net of cash distributions		—			(2	)
Risk-management activities		(97	)		(52	)
Gain on sale of assets, net		—			(4	)
Deferred income taxes		32			(96	)
Legal and settlement charges		11			23
Debt conversion charges		—			202
Other		10			28
Changes in working capital:
Accounts receivable		(130	)		294
Inventory		(3	)		4
Prepayments and other assets		(18	)		55
Accounts payable and accrued liabilities		122			(808	)
Changes in non-current assets		(17	)		(5	)
Changes in non-current liabilities		3			4

Net cash provided by (used in) operating activities		171			(378	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(153	)		(59	)
Proceeds from asset sales, net		—			3
Business acquisitions, net of cash acquired		17			—
Net proceeds from exchange of unconsolidated investments, net of cash acquired		—			165
Decrease in restricted cash and restricted investments		(589	)		162
Affiliate transactions		(12	)		4
Other investing		—			(3	)

Net cash provided by (used in) investing activities		(737	)		272

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net		2,663			1,071
Repayments of long-term borrowings		(1,719	)		(1,683	)
Debt conversion costs		—			(202	)
Repayments from affiliate, net		—			(120	)
Dividends to affiliate		(342	)		(50	)
Other financing, net		1			(1	)

Net cash provided by (used in) financing activities		603			(985	)

Net increase (decrease) in cash and cash equivalents		37			(1,091	)
Cash and cash equivalents, beginning of period		243			1,326

Cash and cash equivalents, end of period	$	280		$	235

See the notes to condensed consolidated financial statements.

DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited) (in millions)


	Three Months Ended June 30,
	2007			2006
Net income (loss)	$	90		$	(181	)
Cash flow hedging activities, net:
Unrealized mark-to-market gains arising during period, net		—			12
Reclassification of mark-to-market gains to earnings, net		(13	)		(3	)

Changes in cash flow hedging activities, net (net of tax benefit (expense) of $8 and ($5), respectively)		(13	)		9
Recognized prior service cost and actuarial loss		1			—
Unrealized loss on securities, net of tax benefit of $1		(2	)		—
Foreign currency translation adjustment		2			3

Other comprehensive income (loss), net of tax		(12	)		12

Comprehensive income (loss)	$	78		$	(169	)


	Six Months Ended June 30,
	2007			2006
Net income (loss)	$	112		$	(178	)
Cash flow hedging activities, net:
Unrealized mark-to-market gains (losses) arising during period, net		(59	)		25
Reclassification of mark-to-market gains to earnings, net		(28	)		(12	)

Changes in cash flow hedging activities, net (net of tax benefit (expense) of $51 and ($8), respectively)		(87	)		13
Recognized prior service cost and actuarial loss		2			—
Unrealized loss on securities, net of tax benefit of $1		(2	)		—
Foreign currency translation adjustment		2			3

Other comprehensive income (loss), net of tax		(85	)		16

Comprehensive income (loss)	$	27		$	(162	)

See the notes to condensed consolidated financial statements.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

Note 1—Accounting Policies

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with the instructions to interim financial reporting as prescribed by the SEC. The year-end condensed consolidated balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. These interim financial statements should be read together with the consolidated financial statements and notes thereto included in Dynegy’s Form 10-K for the year ended December 31, 2006 filed on February 27, 2007, as amended on April 30, 2007, and DHI’s Form 10-K for the year ended December 31, 2006 filed on March 14, 2007, which we refer to as each registrant’s “Form 10-K”.

In April 2007, Dynegy completed its acquisition of 11 power generation facilities and a 50% interest in certain power generation development projects from LS Power Associates, L.P. Dynegy’s interests in the 11 power generation facilities was subsequently contributed to DHI. Please see Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions for further discussion.

In April 2007, Dynegy contributed to DHI its interest in Dynegy New York Holdings Inc. (“New York Holdings”). This contribution was accounted for as a transaction between entities under common control. As such, the assets and liabilities of New York Holdings were recorded by DHI at Dynegy’s historical cost on the acquisition date. This Form 10-Q with respect to DHI reflects the contribution as though DHI had owned New York Holdings in all periods presented. Please see Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions—Sithe Assets Contribution for further discussion.

The unaudited condensed consolidated financial statements contained in this report include all material adjustments of a normal and recurring nature that, in the opinion of management, are necessary for a fair statement of the results for the interim periods. The results of operations for the interim periods presented in this Form 10-Q are not necessarily indicative of the results to be expected for the full year or any other interim period due to seasonal fluctuations in demand for our energy products and services, changes in commodity prices, timing of maintenance and other expenditures and other factors. The preparation of the unaudited condensed consolidated financial statements in conformity with GAAP requires management to make estimates and judgments that affect our reported financial position and results of operations. These estimates and judgments also impact the nature and extent of disclosure, if any, of our contingent liabilities. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments prior to their publication. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are primarily used in (i) developing fair value assumptions, including estimates of future cash flows and discount rates, (ii) analyzing goodwill and tangible and intangible assets for possible impairment, (iii) estimating the useful lives of our assets, (iv) assessing future tax exposure and the realization of tax assets, (v) determining amounts to accrue for contingencies, guarantees and indemnifications and (vi) estimating various factors used to value our pension assets and liabilities. Actual results could differ materially from any such estimates. Certain reclassifications have been made to prior period amounts in order to conform to current year presentation.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

Goodwill and Other Intangible Assets

Goodwill represents, at the time of an acquisition, the amount of purchase price paid in excess of the fair value of net assets acquired. We follow the guidance set forth in SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”), when assessing the carrying value of our goodwill. Accordingly, we will evaluate our goodwill for impairment on an annual basis and when events warrant an assessment. Our evaluation is based, in part, on our estimate of future cash flows. The estimation of fair value is highly subjective, inherently imprecise and can change materially from period to period based on, among other things, an assessment of market conditions, projected cash flows and discount rate.

Intangible assets represent the fair value of assets, apart from goodwill, that arise from contractual rights or other legal rights. In accordance with SFAS No. 141, “Business Combinations” (“SFAS No. 141”), we record only those intangible assets that are distinctly separable from goodwill and can be sold, transferred, licensed, rented, or otherwise exchanged in the open market. Additionally, we recognize intangible assets for those assets that can be exchanged in combination with other rights, contracts, assets or liabilities.

In accordance with SFAS No. 142, we initially record and measure intangible assets based on the fair value of those rights transferred in the exchange transaction in which the asset was acquired. Those measurements are based on quoted market prices for the asset, if available, or measurement techniques based on the best information available such as a present value of future cash flows measurement. Present value measurement techniques involve judgments and estimates made by management about prices, cash flows, discount factors and other variables and the actual value realized from those assets could vary materially from these judgments and estimates. We amortize intangible assets based on the useful life of the respective asset as measured by either the life of the contract or right that the asset is derived from. If the intangible asset does not have a finite life based on the contractual or legal right, an estimate is made of the useful life based on the pattern in which the economic benefits of the asset are expected to be consumed. Intangible assets are also subjected to impairment testing on a regular basis and an impairment loss is recognized if the carrying amount of an intangible exceeds its fair value. Please see Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions for further discussion

Accounting Principles Adopted

FIN No. 48. On July 12, 2006, the FASB issued FIN No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN No. 48”), which provides clarification of SFAS 109, “Accounting for Income Taxes” with respect to the recognition of income tax benefits of uncertain tax positions in the financial statements. FIN No. 48 requires that uncertain tax positions be reviewed and assessed with recognition and measurement of the tax benefit based on a “more-likely-than-not” standard. We adopted the provisions of FIN No. 48 on January 1, 2007 and recorded a decrease of $7 million and $13 million, respectively, to Dynegy’s and DHI’s accumulated deficits as of January 1, 2007 to reflect the cumulative effect of adopting FIN No. 48.

As of January 1, 2007, Dynegy and DHI had approximately $111 million and $75 million, respectively, of unrecognized tax benefits, of which $67 million and $37 million, respectively, would impact their effective tax rates.

As of June 30, 2007, Dynegy and DHI had approximately $56 million and $43 million, respectively, of unrecognized tax benefits, of which $45 million and $31 million, respectively, would impact their effective tax rates if recognized. The changes to Dynegy’s and DHI’s unrecognized tax benefits during the second quarter 2007 primarily resulted from effective settlement of an IRS audit for the tax years 2001 and 2002.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

Additionally, in conjunction with the adoption of FIN No. 48 as of January 1, 2007, we reduced our regular federal tax NOL carryforwards by $253 million, from $948 million to $695 million. The reduction was offset by corresponding changes to our net deferred tax liability and reserve for uncertain tax positions.

We recognize accrued interest expense and penalties related to unrecognized tax benefits as income tax expense. Dynegy had approximately $5 million accrued for the payment of interest and penalties at June 30, 2007 and January 1, 2007, respectively. DHI had approximately $7 million and $6 million accrued for the payment of interest and penalties at June 30, 2007 and January 1, 2007, respectively.

We expect that our unrecognized tax benefits could continue to change due to the settlement of audits and the expiration of statutes of limitation in the next twelve months; however, we do not anticipate any such change to have a significant impact on our results of operations, our financial position or cash flows.

Dynegy files a consolidated income tax return in the U.S. federal jurisdiction, and we file other income tax returns in various states and foreign jurisdictions. DHI is included in Dynegy’s consolidated federal tax returns. With few exceptions, we are no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for years before 2001. The IRS commenced an examination of Dynegy’s U.S. consolidated income tax returns for 2004 and 2005 in the second quarter 2006 that is anticipated to be completed by the end of 2007. The IRS examination for 2001 through 2002 was completed in January 2006. Dynegy has effectively settled the audit issues in the second quarter 2007, and is awaiting final resolution on interest computations with the IRS. The CRA is currently examining Canadian income tax returns for 2002 through 2004 and we are expecting completion of the audit in late 2007.

Accounting Principles Not Yet Adopted

SFAS No. 157. On September 15, 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements. SFAS No. 157 does not require any new fair value measurements; however, the application of SFAS No. 157 will change current practice for some entities. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the impact of this statement on our financial statements.

SFAS No. 159. On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure eligible items at fair value at specified election dates. A business entity will report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the impact of this statement on our financial statements.

Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions

LS Power Business Combination. On March 29, 2007, at a special meeting of the shareholders of Dynegy Illinois, the shareholders of Dynegy Illinois (i) adopted the Plan of Merger, Contribution and Sale Agreement, dated as of September 14, 2006 (the “Merger Agreement”), by and among Dynegy, Dynegy Illinois, Falcon Merger Sub Co., an Illinois corporation and a then-wholly owned subsidiary of Dynegy (“Merger Sub”), LSP Gen Investors,

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

L.P., LS Power Partners, L.P., LS Power Equity Partners PIE I, L.P., LS Power Equity Partners, L.P. and LS Power Associates, L.P. (“LS Associates” and, collectively, the “LS Contributing Entities”) and (ii) approved the merger of Merger Sub with and into Dynegy Illinois (the “Merger”).

On April 2, 2007, in accordance with the Merger Agreement, (i) the Merger was effected, as a result of which Dynegy Illinois became a wholly owned subsidiary of Dynegy and each share of the Class A common stock and Class B common stock of Dynegy Illinois outstanding immediately prior to the Merger was converted into the right to receive one share of the Class A common stock of Dynegy, and (ii) the LS Contributing Entities transferred all of the interests owned by them in entities that own 11 power generation facilities to Dynegy (the “Contributed Entities”).

As part of the transactions contemplated by the Merger Agreement, LS Associates transferred its interests in certain power generation development projects to DLS Power Holdings, LLC, a newly formed Delaware limited liability company (“DLS Power Holdings”), and contributed 50% of the membership interests in DLS Power Holdings to Dynegy. In addition, immediately after the completion of the Merger, LS Associates and Dynegy each contributed $5 million to DLS Power Holdings as their initial capital contributions, and also contributed their respective interests in certain additional power generation development projects to DLS Power Holdings. In connection with the formation of DLS Power Holdings, LS Associates formed DLS Power Development Company, LLC, a Delaware limited liability company (“DLS Power Development”). LS Associates and Dynegy each now own 50% of the membership interests in DLS Power Development.

The aggregate purchase price was comprised of (i) $100 million cash, (ii) 340 million shares of the Class B common stock of Dynegy, (iii) the issuance of a promissory note in the aggregate principal amount of $275 million (the “Note”) (which was simultaneously issued and repaid in full without interest or prepayment penalty), (iv) the issuance of an additional $70 million of project-related debt (the “Griffith Debt”) (which was simultaneously issued and repaid in full without interest or prepayment penalty) via an indirect wholly owned subsidiary, and (v) transaction costs of approximately $52 million, approximately $8 million of which were paid in 2006. The Class B common stock issued by Dynegy was valued at $5.98 per share, which represents the average closing price of Dynegy’s common stock on the New York Stock Exchange for the two days prior to, including, and two days subsequent to the September 15, 2006 public announcement of the Merger, or approximately $2,033 million. Dynegy funded the cash payment and the repayment of the Note and the Griffith Debt using cash on hand and borrowings by DHI (and subsequent permitted distributions to Dynegy) of (i) an aggregate $275 million under the Revolving Facility (as defined below) and (ii) an aggregate $70 million under the new Term Loan B (as defined below). Please read Note 6—Debt—Fifth Amended and Restated Credit Facility for further discussion. We paid a premium over the fair value of the net tangible and identified intangible assets acquired due to the (i) scale and diversity of assets acquired in key regions of the United States; (ii) financial stability, and (iii) proven nature of the LS Power asset development platform that were subsequently contributed to DLS Power Holdings and DLS Power Development.

The application of purchase accounting under SFAS No. 141 requires that the total purchase price be allocated to the fair value of assets acquired and liabilities assumed based on their fair values at the acquisition date, with amounts exceeding the fair values being recorded as goodwill in accordance with SFAS No. 142. The allocation process requires an analysis of acquired fixed assets, contracts, and contingencies to identify and record the fair value of all assets acquired and liabilities assumed. Dynegy’s allocation of the purchase price to specific assets and liabilities is based, in part, upon outside appraisals using customary valuation procedures and techniques. The purchase price allocation is preliminary, as Dynegy is finalizing its valuation of tangible and intangible assets acquired. Dynegy expects to complete the purchase price allocation in the third quarter 2007. However, the differences between the final and preliminary purchase price allocations, if any, are not expected to have a material effect on Dynegy’s financial position or results of operations. The following table summarizes the preliminary fair values of the assets acquired and liabilities assumed at the date of acquisition (in millions):

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006


Cash	$	17
Restricted cash and investments (including $37 million current)		91
Accounts receivable		52
Inventory		37
Assets from risk management activities (including $11 million current)		36
Prepaids and other current assets		19
Property, plant and equipment		4,223
Goodwill		660
Unconsolidated investments		83
Other		47

Total assets acquired	$	5,265

Current liabilities and accrued liabilities	$	(89	)
Liabilities from risk management activities (including $14 million current)		(76	)
Long-term debt (including $32 million current)		(1,898	)
Deferred income taxes		(605	)
Other		(92	)
Minority interest		25

Total liabilities and minority interest assumed	$	(2,735	)

Net assets acquired	$	2,530

As noted above, Dynegy recorded preliminary goodwill of approximately $660 million. Because the purchase price allocation is not complete, it is not practicable to complete the assignment of goodwill to Dynegy’s reporting units.

Dynegy recorded net intangible liabilities of $7 million. This consisted of intangible assets of $32 million in GEN-WE offset by intangible liabilities of $4 million and $35 million, respectively, in GEN-NE and GEN-MW. The intangible assets primarily relate to power tolling agreements that are being amortized over their respective contract terms ranging from 6 months to 7 years. Aggregate amortization expense associated with the above intangibles recorded in the three months ended June 30, 2007 was approximately $2 million. The estimated amortization expense for the six months ended December 31, 2007 is approximately $8 million and for each of the five succeeding years is approximately $8 million, $8 million, $8 million, less than $1 million and less than $1 million, respectively.

Of the $39 million in intangible liabilities, $8 million relates to power tolling agreements which are being amortized over their respective contract terms ranging from 2 years to 10 years. Aggregate amortization income associated with the intangible power tolling agreements recorded in the three months ended June 30, 2007 was less than $1 million. The estimated amortization income for the six months ended December 31, 2007 is $3 million and for each of the five succeeding years is $4 million, $4 million, $2 million, $2 million and $2 million, respectively.

In addition, LSP Kendall Holding LLC, one of the entities transferred to Dynegy, and ultimately DHI, by the LS Contributing Entities pursuant to the Merger Agreement, was party to a power tolling agreement with another of our subsidiaries. This power tolling agreement had a fair value of approximately $31 million as of April 2, 2007,

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

representing a liability from the perspective of LSP Kendall Holding LLC. Upon completion of the Merger Agreement, this power tolling agreement was effectively settled, which resulted in a second quarter 2007 gain equal to the fair value of this contract, in accordance with EITF Issue 04-01, “Accounting for Pre-existing Contractual Relationships Between the Parties to a Purchase Business Combination” (“EITF Issue 04-1”). We recorded a second quarter 2007 pre-tax gain of approximately $31 million, included as a reduction to cost of sales on its unaudited condensed consolidated statements of operations.

The differences between the financial and tax bases of purchased intangibles and goodwill are not deductible for tax purposes. However, purchase accounting allows for the establishment of deferred tax liabilities on purchased intangibles (other than goodwill) that will be reflected as a tax benefit on our future consolidated statements of operations in proportion to and over the amortization period of the related intangible asset.

Dynegy’s results of operations include the results of the acquired entities for the period beginning April 2, 2007. The following table presents unaudited pro forma information for 2006, as if the acquisition had occurred on April 1, 2006:


	Three Months Ended June 30, 2006
	Actual			Pro Forma
	(in millions, except per share amounts)
Revenue	$	379		$	563
Loss before cumulative effect of a change in accounting principal		(207	)		(206	)
Net loss applicable to common stockholders		(211	)		(210	)

Basic and diluted loss per share before cumulative effect of accounting change	$	(0.48	)	$	(0.27	)
Basic and diluted loss per share		(0.48	)		(0.27	)

The following table presents unaudited pro forma information for 2007 and 2006, as if the acquisition had occurred on January 1, 2007 or 2006, respectively:


	Six Months Ended June 30, 2007				Six Months Ended June 30, 2006
	Actual		Pro Forma		Actual			Pro Forma
	(in millions, except per share amounts)
Revenue	$	1,333	$	1,622	$	919		$	1,131
Income (loss) before cumulative effect of a change in accounting principal		90		41		(207	)		(192	)
Net income (loss) applicable to common stockholders		90		41		(215	)		(200	)

Basic earnings (loss) per share before cumulative effect of accounting change	$	0.14	$	0.04	$	(0.51	)	$	(0.26	)
Diluted earnings (loss) per share before cumulative effect of accounting change		0.13		0.03		(0.51	)		(0.26	)
Basic earnings (loss) per share		0.14		0.04		(0.51	)		(0.26	)
Diluted earnings (loss) per share		0.13		0.03		(0.51	)		(0.26	)

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

occurred on April 1, 2006 for the three months ended June 30, 2006 or on January 1, 2007 and 2006, respectively, for the six months ended June 30, 2007 and 2006 Pro forma adjustments to the results of operations include the effects on depreciation and amortization, interest expense, interest income and income taxes. The unaudited pro forma condensed consolidated financial statements reflect the Merger in accordance with SFAS No. 141 and SFAS No. 142.

The consummation of the Merger Agreement with the LS Contributing Entities constituted a change in control as defined in our severance pay plans, as well as the various long-term incentive award grant agreements. As a result, all outstanding restricted stock and stock option awards previously granted to employees vested in full on April 2, 2007 upon the closing of the Merger Agreement. Specifically, the vesting of the restricted stock awards granted in 2005 and 2006 and the unvested tranches of stock option awards granted in those years were accelerated. Accordingly, we recorded a charge of approximately $6 million in the second quarter 2007, included in general and administrative expense on our unaudited condensed consolidated statement of operations.

LS Assets Contribution. In April 2007, in connection with the completion of the Merger Agreement, Dynegy contributed to Dynegy Illinois its interest in the Contributed Entities. Following such contribution, Dynegy Illinois contributed to DHI its interest in the Contributed Entities and, as a result, the Contributed Entities are subsidiaries of DHI. As a result, all of the entities acquired in the Merger are included within DHI with the exception of Dynegy’s 50% interests in DLS Power Holdings and DLS Power Development, which are directly owned by Dynegy.

DHI’s results of operations include the results of the acquired entities for the period beginning April 2, 2007. The following table presents unaudited pro forma information for 2006, as if the acquisition and subsequent contribution had occurred on April 1, 2006:


	Three Months Ended June 30, 2006
	Actual			Pro Forma
	(in millions, except per share amounts)
Revenue	$	379		$	563
Net loss		(181	)		(180	)

The following table presents unaudited pro forma information for 2007 and 2006, as if the acquisition and subsequent contribution had occurred on January 1, 2007 or 2006, respectively:


	Six Months Ended June 30, 2007				Six Months Ended June 30, 2006
	Actual		Pro Forma		Actual			Pro Forma
	(in millions, except per share amounts)
Revenue	$	1,333	$	1,622	$	919		$	1,131
Net income (loss)		112		63		(178	)		(163	)

These unaudited pro forma results, based on assumptions deemed appropriate by management, have been prepared for informational purposes only and are not necessarily indicative of DHI’s results if the Merger had occurred on April 1, 2006 for the three months ended June 30, 2006 or on January 1, 2007 and 2006, respectively, for the six months ended June 30, 2007 and 2006. Pro forma adjustments to the results of operations include the effects on depreciation and amortization, interest expense, interest income and income taxes. The unaudited pro forma condensed consolidated financial statements reflect the Merger in accordance with SFAS No. 141 and SFAS No. 142.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

Sithe Assets Contribution. Also in April 2007, Dynegy Illinois contributed to DHI all of its interest in New York Holdings, together with its indirect interest in the subsidiaries of New York Holdings. New York Holdings, together with its wholly owned subsidiaries, owns various assets in the Northeast, which we commonly refer to as the “Sithe Assets”. The Sithe Assets primarily consist of the Sithe/Independence Power Partners, L.P. (“Independence”), a 1,064 MW facility located in Scriba, New York, which Dynegy Illinois acquired in January 2005. This contribution was accounted for as a transaction between entities under common control. As such, the assets and liabilities of New York Holdings were recorded by DHI at Dynegy’s historical cost on the date of contribution. In addition, DHI’s historical financial statements have been adjusted in all periods presented to reflect the contribution as though DHI had owned New York Holdings in all periods presented. Independence holds a power tolling contract with DHI. As a result of the contribution, our Independence toll has become an intercompany agreement in our GEN-NE segment and the financial statement impact has been eliminated. The Sithe Assets contributed to DHI also include four hydroelectric generation facilities in Pennsylvania. Please read Note 7—Variable Interest Entities for further information.

Note 3—Discontinued Operations

GEN-WE Discontinued Operations

CoGen Lyondell. On August 1, 2007, we completed our sale of our CoGen Lyondell power generation facility for approximately $470 million to EnergyCo., LLC (“EnergyCo.”), a joint venture between PNM Resources and a subsidiary of Cascade Investment, LLC. We expect to record an estimated $200 million gain related to the sale of the asset in the third quarter 2007.

Beginning in the second quarter 2007, CoGen Lyondell met the held for sale classification requirements of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS No. 144”), and is classified as such on our unaudited condensed consolidated balance sheet. The major classes of current and long-term assets classified as assets held for sale at June 30, 2007 are $189 million of property, plant and equipment, net, $6 million of inventory, $70 million of goodwill, $18 million of deferred tax liabilities, and $1 million of accrued liabilities and other current liabilities. The goodwill allocated to CoGen Lyondell is preliminary and could change upon finalization of the LS purchase price allocation. Any change to the allocated goodwill would have a corresponding change to our estimated $200 million gain related to the sale of the asset. As the goodwill is not deductible for tax purposes, any change in the goodwill allocated to CoGen Lyondell will also impact the annual effective tax rate for discontinued operations. Please see Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions—LS Power Business Combination for further discussion.

In accordance with SFAS No. 144, we discontinued depreciation and amortization of CoGen Lyondell’s property, plant and equipment during the second quarter 2007. Depreciation and amortization expense related to CoGen Lyondell totaled approximately $1 million and $5 million in the three- and six-month periods ended June 30, 2007, respectively, compared to approximately $3 million and $5 million in the three- and six-month periods ended June 30, 2006, respectively. Also pursuant to SFAS No. 144, we are reporting the results of CoGen Lyondell’s operations as a discontinued operation. Accordingly, the facility’s results have been included in discontinued operations for all periods presented.

Calcasieu. On January 31, 2007, we entered into an agreement to sell our interest in the Calcasieu power generation facility to Entergy Gulf States, Inc. (“Entergy”) for approximately $57 million, subject to regulatory approval and other closing conditions. The transaction is expected to close in early 2008. Beginning in the first quarter 2007, Calcasieu met the held for sale classification requirements of SFAS No. 144, and is classified as such on our unaudited condensed consolidated balance sheet. The major classes of current and long-term assets classified

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

as assets held for sale at June 30, 2007 are approximately $57 million of property, plant and equipment, net, $1 million of inventory, $1 million of deferred tax liabilities, and $1 million of accrued liabilities and other current liabilities.

In accordance with SFAS No. 144, we discontinued depreciation and amortization of Calcasieu’s property, plant and equipment during the first quarter 2007. Depreciation and amortization expense related to Calcasieu totaled less than $1 million and $1 million in the three- and six-month periods ended June 30, 2007, respectively, compared to less than $1 million and approximately $1 million in the three- and six-month periods ended June 30, 2006, respectively. Also pursuant to SFAS No. 144, we are reporting the results of Calcasieu’s operations as a discontinued operation. Accordingly, the facility’s results have been included in discontinued operations for all periods presented.

Other Discontinued Operations

Natural Gas Liquids. On October 31, 2005, we completed the sale of DMSLP, which comprised substantially all remaining operations of our NGL segment, to Targa Resources Inc. (“Targa”) and two of its subsidiaries for $2.44 billion in cash.

Other. We sold or liquidated some of our operations during 2003, including our U.K. CRM business, which have been accounted for as discontinued operations under SFAS No. 144.

The following table summarizes information related to Dynegy’s discontinued operations:


	GEN-WE			CRM			NGL			Total
Three Months Ended June 30, 2007
Income from operations before taxes	$	3		$	11		$	—		$	14
Income (loss) from operations after taxes		(3	)		8			4			9
Three Months Ended June 30, 2006
Loss from operations before taxes	$	(1	)	$	(2	)	$	—		$	(3	)
Income (loss) from operations after taxes		—			1			(1	)		—

	GEN-WE			CRM			NGL			Total
Six Months Ended June 30, 2007
Income from operations before taxes	$	—		$	11		$	—		$	11
Income (loss) from operations after taxes		(5	)		8			4			7
Six Months Ended June 30, 2006
Income (loss) from operations before taxes	$	(15	)	$	(1	)	$	1		$	(15	)
Income (loss) from operations after taxes		(9	)		1			—			(8	)

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

The following table summarizes information related to DHI’s discontinued operations:


	GEN-WE			CRM			NGL			Total
Three Months Ended June 30, 2007
Income from operations before taxes	$	3		$	11		$	—		$	14
Income (loss) from operations after taxes		(3	)		7			4			8
Three Months Ended June 30, 2006
Loss from operations before taxes	$	(1	)	$	(2	)	$	—		$	(3	)
Income (loss) from operations after taxes		—			2			(3	)		(1	)

	GEN-WE			CRM			NGL			Total
Six Months Ended June 30, 2007
Income from operations before taxes	$	—		$	11		$	—		$	11
Income from operations after taxes		(5	)		7			4			6
Six Months Ended June 30, 2006
Income (loss) from operations before taxes	$	(15	)	$	(1	)	$	1		$	(15	)
Income (loss) from operations after taxes		(9	)		—			—			(9	)

Note 4—Restructuring Charges

2005 Restructuring. In December 2005, in order to better align our corporate cost structure with a single line of business and as part of a comprehensive effort to reduce on-going operating expenses, we implemented a restructuring plan (the “2005 Restructuring Plan”). The 2005 Restructuring Plan resulted in a reduction of approximately 40 positions and was complete by June 30, 2006. We recognized a pre-tax charge, primarily in our Other segment, of $11 million in the fourth quarter 2005. We recognized approximately $2 million of charges in the six months ended June 30, 2006 when transitional services were completed by certain affected employees. These charges related entirely to severance costs.

2002 Restructuring. In October 2002, we announced a restructuring plan designed to improve operational efficiencies and performance across our lines of business.

The following is a schedule of 2007 activity for the liabilities recorded in connection with this restructuring:


	Severance		Cancellation Fees and Operating Leases			Total
			(in millions)
Balance at December 31, 2006	$	3	$	7		$	10
Cash payments		—		(2	)		(2	)

Balance at June 30, 2007	$	3	$	5		$	8

We expect the $5 million accrual as of June 30, 2007 associated with cancellation fees and operating leases to be paid by the end of 2007, when the leases expire.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Discontinued Operations—Natural Gas Liquids beginning on page F-23 and F-18, respectively, of Dynegy’s and DHI’s Forms 10-K for further information.

Note 5—Risk Management Activities

The nature of our business necessarily involves market and financial risks. We enter into financial instrument contracts in an attempt to mitigate or eliminate these various risks. These risks and our strategy for mitigating them are more fully described in Note 6—Risk Management Activities and Financial Instruments beginning on page F-26 and F-21, respectively, of Dynegy’s and DHI’s Forms 10-K.

Cash Flow Hedges. We enter into financial derivative instruments that qualify, and that we may elect to designate, as cash flow hedges. Interest rate swaps have been used to convert floating interest rate obligations to fixed interest rate obligations. Instruments related to our GEN business, which are entered into for purposes of hedging future fuel requirements and sales commitments and locking in commodity prices we consider favorable under the circumstances, have also historically been designated as cash flow hedges. Beginning on April 2, 2007, we chose to cease designating such instruments related to our GEN business as cash flow hedges, and thus apply mark-to-market accounting treatment prospectively. Therefore, beginning with the second quarter 2007, these instruments receive mark-to-market accounting treatment. Accordingly, as values fluctuate from period to period due to market price volatility, value changes are reflected on the income statement. Pursuant to EITF Issue 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (“EITF Issue No. 02-3”), all gains and losses on third party energy trading contracts, whether realized or unrealized, are presented net in the consolidated statements of operations. The balance in Other Comprehensive Income at April 2, 2007 related to these instruments will be reclassified to future earnings contemporaneously with the related purchases of fuel and sales of electricity. As of June 30, 2007, this amount totaled $24 million pre-tax.

During the three and six months ended June 30, 2007, we recorded zero and $5 million, respectively, of income related to ineffectiveness from changes in the fair value of hedge positions, and no amounts were excluded from the assessment of hedge effectiveness related to the hedge of future cash flows. During the three and six months ended June 30, 2006, we recorded $4 million related to ineffectiveness from changes in fair value of hedge positions, and no amounts were excluded from the assessment of hedge effectiveness related to the hedge of future cash flows. During the three and six months ended June 30, 2007 and 2006, no amounts were reclassified to earnings in connection with forecasted transactions that were no longer considered probable of occurring.

The balance in cash flow hedging activities, net at June 30, 2007 is expected to be reclassified to future earnings, contemporaneously with the related purchases of fuel, sales of electricity and payments of interest, as applicable to each type of hedge. Of this amount, after-tax gains of approximately $16 million are currently estimated to be reclassified into earnings over the 12-month period ending June 30, 2008. The actual amounts that will be reclassified to earnings over this period and beyond could vary materially from this estimated amount as a result of changes in market conditions and other factors.

Fair Value Hedges. We also enter into derivative instruments that qualify, and that we designate, as fair value hedges. We use interest rate swaps to convert a portion of our non-prepayable fixed-rate debt into floating-rate debt. During the three and six months ended June 30, 2007 and 2006, there was no ineffectiveness from changes in the fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness. During the three and six months ended June 30, 2007 and 2006, no amounts were recognized in relation to firm commitments that no longer qualified as fair value hedges.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

Net Investment Hedges in Foreign Operations. Although we have exited a substantial amount of our foreign operations, we have remaining investments in foreign subsidiaries, the net assets of which are exposed to currency exchange-rate volatility. As of June 30, 2007, we had no net investment hedges in place.

Note 6—Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income, net of tax, is included in Dynegy’s stockholders’ equity and DHI’s stockholder’s equity on our unaudited condensed consolidated balance sheets, respectively, as follows:


	June 30, 2007			December 31, 2006
	(in millions)
Cash flow hedging activities, net	$	(11	)	$	76
Foreign currency translation adjustment		25			23
Unrecognized prior service cost and actuarial loss		(41	)		(43	)
Available for sale securities		9			11

Accumulated other comprehensive income (loss), net of tax	$	(18	)	$	67

Note 7—Variable Interest Entities

Hydroelectric Generation Facilities. On January 31, 2005, Dynegy completed the acquisition of ExRes SHC, Inc. (“ExRes”), the parent company of Sithe Energies, Inc. and Independence. As further discussed in Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions—Sithe Assets Contribution, on April 2, 2007, Dynegy contributed its interest in the Sithe Assets to DHI. ExRes, also owns through its subsidiaries four hydroelectric generation facilities in Pennsylvania. The entities owning these facilities meet the definition of VIEs. In accordance with the purchase agreement, Exelon Corporation, which we refer to as “Exelon,” has the sole and exclusive right to direct our efforts to decommission, sell, or otherwise dispose of the hydroelectric facilities owned through the VIEs. Exelon is obligated to reimburse ExRes for all costs, liabilities, and obligations of the entities owning these facilities, and to indemnify ExRes with respect to the past and present assets and operations of the entities. As a result, we are not the primary beneficiary of the entities and have not consolidated them in accordance with the provisions of FIN No. 46(R), “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51” (“FIN No. 46(R)”).

These hydroelectric generation facilities have commitments and obligations that are off-balance sheet with respect to us that arise under operating leases for equipment and long-term power purchase agreements with local utilities. As of June 30, 2007, the equipment leases have remaining terms from one to twenty-five years and involve a maximum aggregate obligation of $153 million over the terms of the leases. Additionally, each of these facilities is party to a long-term power purchase agreement with a local utility. Under the terms of each of these agreements, a project tracking account, which we refer to as a “Tracking Account,” was established to quantify the difference between (i) the facility’s fixed price revenues under the power purchase agreement and (ii) a percentage of the respective utility’s Public Utility Commission approved avoided costs associated with those power purchases plus accumulated interest on the balance. Each power purchase agreement calls for the hydroelectric facility to return to the utility the balance in the Tracking Account before the end of the facility’s life through decreased pricing under the respective power purchase agreement. If the decreased pricing does not reduce the tracking account to zero, a lump sum payment for the remainder of the balance will be due. All four hydroelectric facilities are currently in the

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

Tracking Account repayment period of the contract, whereby balances are repaid through decreased pricing. This pricing cannot be decreased below a level sufficient to allow the facilities to recover their operating costs. The aggregate balance of the Tracking Accounts as of June 30, 2007, was approximately $338 million, and the obligations with respect to each Tracking Account are secured by the assets of the respective facility. The decreased pricing necessary to reduce the Tracking Accounts will make the continued sale of electricity from the facilities uneconomical. As discussed above, the obligations of the four hydroelectric facilities are non-recourse to us. Under the terms of the stock purchase agreement with Exelon, we are indemnified for any net cash outflow arising from ownership of these facilities.

PPEA Holding Company LLC. On April 2, 2007, in connection with the completion of the Merger Agreement, we acquired a 70% interest in PPEA Holding Company LLC (“PPEA”). PPEA owns and operates Plum Point Energy Associates, LLC (“Plum Point”) which is constructing a 665 MW coal fired power plant (the “Project”), located in Mississippi County, Arkansas. Plum Point is the Borrower under a $700 million term loan facility, a $17 million revolving credit facility, and a $102 million letter of credit facility. The Project indebtedness is held by Plum Point. The payment obligations of Plum Point in respect of the Bank Loan, the Revolver, the LC Facility, and $100 million of Tax Exempt Bonds (as discussed below in Note 8) are unconditionally and irrevocably guaranteed by Ambac Assurance Corporation, an independent third party insurance company. PPEA is party to credit facilities and an insurance policy, which are secured by a security interest in all of Plum Point’s assets, contract rights and Plum Point’s undivided tenancy in common interest in the Project. These assets consist primarily of $189 million of plant construction in progress at June 30, 2007. There are no guarantees of the indebtedness by any other parties, and PPEA’s creditors have no recourse against our general credit. See Note 8—Debt—Plum Point Term facility for discussion of PPEA’s borrowings. PPEA meets the definition of a VIE, and we have determined we are the primary beneficiary of this entity. As such, we have consolidated it in accordance with the provisions of FIN No. 46(R).

DLS Power Holdings and DLS Power Development. As discussed in Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions, on April 2, 2007, in connection with the transactions consummated by the Merger Agreement, Dynegy acquired a 50% interest in DLS Power Holdings and DLS Power Development. The purpose of DLS Power Development is to provide services to DLS Power Holdings and the project subsidiaries related to power project development and to evaluate and pursue potential new development projects. DLS Power Holdings and DLS Power Development meet the definition of VIEs, as they will require additional subordinated financial support from their owners to conduct normal on-going operations. However, Dynegy is not the primary beneficiary of the entities and, in accordance with the provisions of FIN No. 46(R), has not consolidated them. Dynegy accounts for its investments in DLS Power Holdings and DLS Power Development as equity method investments pursuant to APB 18, “The Equity Method of Accounting for Investments in Common Stock”. We believe that Dynegy’s maximum exposure to economic loss from this VIE is limited to $86 million, which represents our equity investment in these entities.

A substantial portion of the $83 million purchase price allocated to these investments represents Dynegy’s estimate of its proportionate share of the fair value of the underlying intangible assets associated with each of the development projects in excess of the equity of the underlying assets. Depending on the outcome of each development project, Dynegy could be required to record an impairment to its investment related to these intangible assets.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

Note 8—Debt

Notes payable and long-term debt consisted of the following:


	June 30, 2007		December 31, 2006
	(in millions)
Revolver, due 2012	$	275	$	—
Term Loan B, due 2013		70		—
Term Facility, floating rate due 2013		850		—
Term Facility, floating rate due 2012		—		200
Senior Notes, 6.875% due 2011		490		493
Senior Notes, 8.75% due 2012		486		488
Senior Unsecured Notes, 7.5% due 2015		550		—
Senior Unsecured Notes, 8.375% due 2016		1,047		1,047
Senior Debentures, 7.125% due 2018		173		173
Senior Unsecured Notes, 7.75% due 2019		1,100		—
Senior Debentures, 7.625% due 2026		172		173
Second Priority Senior Secured Notes, 9.875% due 2010		11		11
Subordinated Debentures payable to affiliates, 8.316%, due 2027		200		200
Sithe Senior Notes, 8.5% due 2007		20		39
Sithe Senior Notes, 9.0% due 2013		409		409
Plum Point Tax Exempt Bonds, floating rate due 2036		100		—
Plum Point Construction Loan, floating rate due 2010		219		—

		6,172		3,233
Unamortized premium on debt, net		22		25

		6,194		3,258
Less: Amounts due within one year, including non-cash amortization of basis adjustments		54		68

Total Long-Term Debt	$	6,140	$	3,190

Aggregate debt maturities for the remainder of 2007, the next four years and thereafter of the principal amounts of all long-term indebtedness as of June 30, 2007 are as follows: 2008—$39 million, 2009—$58 million, 2010—$74 million, 2011—$570 million and thereafter—$5,399 million.

Fifth Amended and Restated Credit Facility. On April 2, 2007, we entered into a fifth amended and restated credit facility (the “Fifth Amended and Restated Credit Facility”) with Citicorp USA, Inc. and JPMorgan Chase Bank, N.A., as co-administrative agents, JPMorgan Chase Bank, N.A., as collateral agent, Citicorp USA Inc., as payment agent, J.P. Morgan Securities Inc. and Citigroup Global Markets Inc., as joint lead arrangers and joint book-runners, and the other financial institutions party thereto as lenders or letter of credit issuers.

The Fifth Amended and Restated Credit Facility amended DHI’s former credit facility (the Fourth Amended and Restated Credit Facility, which was last amended on July 11, 2006) by increasing the amount of the existing $470 million revolving credit facility (the “Revolving Facility”) to $850 million, increasing the amount of the existing $200 million term letter of credit facility (the “Term L/C Facility”) to $400 million and adding a $70 million senior secured term loan facility (“Term Loan B”).

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

Loans and letters of credit are available under the Revolving Facility and letters of credit are available under the Term L/C Facility for general corporate purposes. Letters of credit issued under DHI’s former credit facility have been continued under the Fifth Amended and Restated Credit Facility. The Term Loan B was used to pay a portion of the consideration under the Merger Agreement. In connection with the completion of the transactions contemplated by the Merger Agreement, an aggregate $275 million under the Revolving Facility, an aggregate $400 million under the Term L/C Facility (with the proceeds placed in a collateral account to support the issuance of letters of credit), and an aggregate $70 million under Term Loan B (representing all available borrowings under Term Loan B) were drawn.

The Fifth Amended and Restated Credit Facility is secured by certain assets of DHI and is guaranteed by Dynegy, Dynegy Illinois and certain subsidiaries of DHI. In addition, the obligations under the Fifth Amended and Restated Credit Facility and certain other obligations to the lenders thereunder and their affiliates are secured by substantially all of the assets of such guarantors. The Revolving Facility matures on April 2, 2012, and the Term L/C Facility and Term Loan B each mature on April 2, 2013. The principal amount of the Term L/C Facility is due in a single payment at maturity; the principal amount of Term Loan B is due in quarterly installments of $175,000 in arrears commencing December 31, 2007, with the unpaid balance due at maturity.

Borrowings under the Fifth Amended and Restated Credit Facility bear interest, at DHI’s option, at either the base rate, which is calculated as the higher of Citibank, N.A.’s publicly announced base rate and the federal funds rate in effect from time to time, or the Eurodollar rate (which is based on rates in the London interbank Eurodollar market), in each case plus an applicable margin.

The applicable margin for borrowings under the Revolving Facility depends on the Standard & Poor’s Ratings Services (“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”) credit ratings of the Revolving Facility, with higher credit ratings resulting in a lower rate. The applicable margin for such borrowings will be either 0.125% or 0.50% per annum for base rate loans and either 1.125% or 1.50% per annum for Eurodollar loans, with the lower applicable margin being payable if the ratings for the Revolving Facility by S&P and Moody’s are BB+ and Ba1 or higher, respectively, and the higher applicable margin being payable if such ratings are less than BB+ and Ba1. The applicable margins for the Term L/C Facility and Term Loan B are 0.50% for base rate loans and 1.50% for Eurodollar loans.

An unused commitment fee of either 0.25% or 0.375% is payable on the unused portion of the Revolving Facility, with the lower commitment fee being payable if the ratings for the Revolving Facility by S&P and Moody’s are BB+ and Ba1 or higher, respectively, and the higher commitment fee being payable if such ratings are less than BB+ and Ba1.

The Fifth Amended and Restated Credit Facility contains mandatory prepayment provisions associated with specified asset sales and dispositions (including as a result of casualty or condemnation). The Fifth Amended and Restated Credit Facility also contains customary affirmative covenants and negative covenants and events of default. Subject to certain exceptions, DHI and its subsidiaries are subject to restrictions on incurring additional indebtedness, limitations on investments and limitations on dividends and other payments in respect of capital stock.

The Fifth Amended and Restated Credit Facility also contains certain financial covenants, including (i) a covenant (measured as of the last day of the relevant fiscal quarter as specified below) that requires DHI and certain of its subsidiaries to maintain a ratio of secured debt to adjusted earnings before interest, taxes, depreciation and amortization (“EBITDA”) for DHI and its relevant subsidiaries of no greater than 3.0:1 (June 30, 2007); 2.75:1 (September 30, 2007 and thereafter through and including March 31, 2009); and 2.5:1 (June 30, 2009 and

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

thereafter); and (ii) a covenant that requires DHI and certain of its subsidiaries to maintain a ratio of adjusted EBITDA to consolidated interest expense for DHI and its relevant subsidiaries as of the last day of the measurement periods ending June 30, 2007 and thereafter through and including December 31, 2008 of no less than 1.5:1; ending March 31, 2009 and June 30, 2009 of no less than 1.625:1; and ending September 30, 2009 and thereafter of no less than 1.75:1.

On May 24, 2007, we entered into an Amendment No. 1, dated as of May 24, 2007 (the “Credit Agreement Amendment”), to the Fifth Amended and Restated Credit Facility, which increased the amount of the existing $850 million Revolving Facility to $1.15 billion and increased the amount of the existing $400 million Term L/C Facility to $850 million; the Credit Agreement Amendment did not affect the Term Loan B. The Credit Agreement Amendment also amended a pro forma leverage ratio requirement in the Fifth Amended and Restated Credit Facility to allow DHI to issue the Notes (as defined and discussed below).

Plum Point Credit Agreement Facility. The Plum Point Credit Agreement Facility (“Credit Agreement Facility”) consists of a $700 million construction loan (the “Construction Loan”), a $700 million term loan commitment (the “Bank Loan”), a $17 million revolving credit facility (the “Revolver”) and a $102 million backstop letter of credit facility (the “LC Facility”). The LC Facility was initially utilized to back-up the $101 million letter of credit issued under the then-existing LC Facility for the benefit of the owners of the Tax Exempt Bonds described below. During the second quarter 2007, the Tax Exempt Bonds were repaid and reoffered and a new letter of credit in the amount of approximately $101 million was carried over from the previous LC Facility for the benefit of the owners of the Tax Exempt Bonds. Borrowings under the Credit Agreement Facility bear interest at PPEA’s option, at either the base rate, which is determined as the greater of the Prime Rate or the Federal Funds Rate in effect from time to time plus ¹/2 of 1% or the Adjusted LIBOR which is equal to the product of the applicable LIBOR and any Statutory Reserves plus an applicable margin equal to .35%. In addition, PPEA pays commitment fees equal to 0.125% per annum on the undrawn Bank Loan, Revolver and LC Facility commitments. Upon completion of the construction of the PPEA facility, the Construction Loan will terminate and the debt there under will be replaced by the Bank Loan. The Bank Loan matures on the thirtieth anniversary of the later of the date on which substantial completion of the facility has occurred or the first date of operation under any of the power purchase agreements then in effect. The current estimated date of completion of construction is in the Fall of 2010.

The payment obligations of PPEA in respect of the Bank Loan, the Revolver, the LC Facility, the Tax Exempt Bonds, and associated interest rate hedging agreements (discussed below) are unconditionally and irrevocably guaranteed by Ambac Assurance Corporation. The insurer also provided an unconditional commitment to issue a debt service reserve surety at closing in an amount equal to the debt service reserve requirement. The credit facilities and insurance policy are secured by a security interest (subject to permitted liens) in all of PPEA’s assets, contract rights and PPEA’s undivided tenancy in common interest in Plum Point. PPEA pays an additional .40% spread for the AMBAC insurance coverage which is deemed a cost of financing and included in interest expense.

In the second quarter 2007, PPEA entered into three interest rate swap agreements with an initial aggregate notional amount of approximately $183 million and fixed interest rates of approximately 5.3%. These interest rate swap agreements convert PPEA’s floating rate debt exposure to a fixed interest rate. The interest rate swap agreements expire in June 2040. For the three months ended June 30, 2007, we recorded $27 million of mark-to-market income related to these interest rate swap agreements as an offset to our consolidated interest expense. Effective July 1, 2007, we designated these agreements as cash flow hedges. Therefore, changes in value after that date will be reflected in Other Comprehensive Income, and subsequently reclassified to interest expense contemporaneously with the related accruals of interest expense to the extent of hedge effectiveness.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

Plum Point Tax Exempt Bonds. On April 1, 2006, the City of Osceola (the “City”) loaned the $100 million in proceeds of a tax exempt bond issuance (the “Tax Exempt Bonds”) to PPEA. The Tax Exempt Bonds were issued pursuant to and secured by a Trust Indenture dated April 1, 2006 between the City, PPEA and Regions Bank as Trustee. The purpose of the Tax Exempt Bonds is to finance certain of PPEA’s undivided interests in various sewage and solid waste collection and disposal facilities. Interest expense on the Tax Exempt Bonds is based on a weekly variable rate and is payable monthly. The interest rate in effect at June 30, 2007 was 3.75%. The Tax Exempt Bonds mature on April 1, 2036.

Senior Unsecured Notes Offering. On May 24, 2007, DHI issued $1.1 billion aggregate principal amount of its 7.75% Senior Unsecured Notes due 2019 (the “2019 Notes) and $550 million aggregate principal amount of its 7.50% Senior Unsecured Notes due 2015 (the “2015 Notes” and, together with the 2019 Notes, the “Notes”) pursuant to the terms of a purchase agreement, dated as of May 17, 2007, by and among DHI and the several initial purchasers party thereto (the “Purchasers”). The Notes are DHI’s senior unsecured obligations and rank equal in right of payment to all of DHI’s existing and future senior unsecured indebtedness, and are senior to all of DHI’s existing, and any of its future, subordinated indebtedness. DHI’s secured debt and its other secured obligations are effectively senior to the Notes to the extent of the value of the assets securing such debt or other obligations. None of DHI’s subsidiaries have guaranteed the Notes and, as a result, all of the existing and future liabilities of DHI’s subsidiaries are effectively senior to the Notes. Dynegy has not guaranteed the Notes, and the assets and operations that Dynegy owns through its subsidiaries, other than DHI, do not support the Notes. In connection with the Notes, DHI entered into a registration rights agreement with the Purchasers of the Notes pursuant to which DHI has agreed to offer to exchange the Notes for a new issue of substantially identical notes registered under the Securities Act of 1933. Under the terms of this offering, DHI has agreed to file an exchange offer registration statement with the SEC. The interest rates on the Notes will increase at an annual rate of 0.25% for each 90-day period during which a failure to register the new Notes continues, up to a maximum increase of 1.0% in the annual interest rates.

DHI used the net proceeds from the sale of the Notes to repay a portion of the debt assumed in the Merger Agreement. Long-term debt assumed upon completion of the Merger Agreement and repaid from the proceeds of the sale of the Notes consisted of the following as of April 2, 2007:


	Face Value		Premium (Discount)			Fair Value
			(in millions)
Generation Facilities First Lien Term Loans due 2013	$	919	$	1		$	920
Generation Facilities Second Lien Term Loans due 2014		150		1			151
Kendall First Lien Term Loan due 2013		396		(5	)		391
Ontelaunee First Lien Term Loan due 2009		100		(1	)		99
Ontelaunee Second Lien Credit Agreement due 2009		50		1			51

Total debt repaid with proceeds from unsecured offering	$	1,615	$	(3	)	$	1,612

Outstanding letters of credit under the Gen Finance LC Facilities were transferred to, and became outstanding letters of credit under, the Fifth Amended and Restated Credit Facility as amended by the Credit Agreement Amendment. Continuing secured obligations of Dynegy Gen Finance Co, LLC include financially settled heat rate options and a collateral posting arrangement that are secured by the assets of Dynegy Gen Finance Co, LLC.

Repayments. On January 2, 2007, we made a $19 million principal payment on the Sithe Energies debt.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

Note 9—Dynegy’s Earnings (Loss) Per Share

Basic earnings (loss) per share represents the amount of earnings (losses) for the period available to each share of Dynegy common stock outstanding during the period. Diluted earnings (loss) per share represents the amount of earnings (losses) for the period available to each share of Dynegy common stock outstanding during the period plus each share that would have been outstanding assuming the issuance of common shares for all dilutive potential common shares outstanding during the period.

The reconciliation of basic earnings (loss) per share from continuing operations to diluted earnings (loss) per share from continuing operations is shown in the following table:


	Three Months Ended June 30,					Six Months Ended June 30,
	2007		2006			2007		2006
	(in millions, except per share amounts)
Income (loss) from continuing operations	$	67	$	(207	)	$	83	$	(199	)
Preferred stock dividends		—		(4	)		—		(9	)

Income (loss) from continuing operations for basic earnings (loss) per share		67		(211	)		83		(208	)
Effect of dilutive securities:
Interest on convertible subordinated debentures		—		1			—		3
Dividends on Series C Preferred		—		4			—		9

Income (loss) from continuing operations for diluted earnings (loss) per share	$	67	$	(206	)	$	83	$	(196	)

Basic weighted-average shares		828		442			663		421
Effect of dilutive securities:
Stock options		2		1			2		1
Convertible subordinated debentures		—		28			—		41
Series C Preferred		—		42			—		56

Diluted weighted-average shares		830		513			665		519

Income (loss) per share from continuing operations:
Basic	$	0.08	$	(0.48	)	$	0.13	$	(0.49	)

Diluted (1)	$	0.08	$	(0.48	)	$	0.12	$	(0.49	)

(1)

When an entity has a net loss from continuing operations, SFAS No. 128, “Earnings per Share”, prohibits the inclusion of potential common shares in the computation of diluted per-share amounts. Accordingly, Dynegy has utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the three and six months ended June 30, 2006.

Note 10—Commitments and Contingencies

Set forth below is a summary of certain ongoing legal proceedings. In accordance with SFAS No. 5, “Accounting for Contingencies” (“SFAS No. 5”), we record reserves for contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable. In addition, we disclose matters for which management believes a material loss is at least reasonably possible. In all instances, management has

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assessed the matters below based on current information and made a judgment concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of damages sought and the probability of success. Management’s judgment may prove materially inaccurate and such judgment is made subject to the known uncertainty of litigation.

In addition to the matters discussed below, we are party to numerous legal proceedings arising in the ordinary course of business or related to discontinued business operations. In management’s opinion, the disposition of these matters will not materially adversely affect our financial condition, results of operations or cash flows.

Bridgeport RMR Agreement. The Bridgeport facility had been operating pursuant to the terms of the Bridgeport reliability-must-run (“RMR”) agreement, subject to the outcome of ongoing proceedings before the FERC to resolve the question of whether Bridgeport is eligible for an RMR agreement. On May 25, 2007, Bridgeport and the intervening parties submitted a Joint Offer of Settlement (the “Settlement”), which effectively terminated the RMR Agreement as of May 31, 2007. In addition, the Settlement stipulated that within 30 days of FERC approval Bridgeport will refund ISO New England (“ISO-NE”) $12.5 million and any RMR revenues received by Bridgeport from the ISO-NE under the amended RMR agreement for the calendar months April 2007 and May 2007. We recorded a reserve of $12.5 million payable to the ISO-NE as part of the LS purchase price allocation, and have reserved any RMR revenues received from the ISO-NE for April and May 2007. Under the Settlement, Bridgeport will no longer be required to submit stipulated bids as of June 1, 2007 therein allowing Bridgeport to more fully participate as a merchant generator in the ISO-NE market. The Settlement was certified as an uncontested settlement on June 29, 2007 by the Presiding Administrative Law Judge and was accepted by the FERC on August 3, 2007.

Illinova Arbitration. In June 2000, Dynegy’s Illinova Generating Company (“IGC”) subsidiary sold a minority interest it held in a Cleburne, Texas generating plant to Ponderosa Pine Energy (“PPE”). Brazos Electric Cooperative, Inc. (“Brazos”), the party to an offtake agreement from the plant, brought legal action against PPE alleging that PPE’s purchase did not comply with the terms of Brazos’ offtake agreement. Brazos received a favorable arbitration award against PPE, which in turn sought recovery from IGC and the other former owners of the plant for indemnification. In May 2007, the panel in PPE’s arbitration action ruled that IGC and the other former owners of the plant must indemnify PPE for the Brazos arbitration award, with IGC’s portion being defined as approximately $17 million. Dynegy recognized a legal settlement charge of approximately $17 million for the first quarter 2007 relating to this adverse ruling and in May 2007 Dynegy paid the judgment under protest. PPE recently moved to enforce the arbitration award in state district court and the defendants have filed an opposition.

Gas Index Pricing Litigation. We and our former joint venture affiliate West Coast Power are named defendants in numerous lawsuits in state and federal court claiming damages resulting from alleged price manipulation and false reporting of natural gas prices. The cases are pending in California, Nevada and Alabama. In each of these suits, the plaintiffs allege that we and other energy companies engaged in an illegal scheme to inflate natural gas prices by providing false information to natural gas index publications. All of the complaints rely heavily on prior FERC and CFTC investigations into and reports concerning index-reporting manipulation in the energy industry. Except as specifically mentioned below, the cases are actively engaged in discovery.

During the last year, several cases pending in Nevada federal court were dismissed on defendants’ motions. Certain plaintiffs have appealed to the Court of Appeals for the Ninth Circuit, which coordinated the cases before the same appellate panel. A decision from the Court of Appeals is expected in late 2007. In February 2007, a Tennessee state court case was also dismissed on defendants’ motion. In April 2007, the plaintiffs appealed the decision.

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Pursuant to various motions, the cases pending in California state court have been coordinated before a single judge in San Diego (“Coordinated Gas Index Cases”). In August 2006, we entered into an agreement to settle the class action claims in the Coordinated Gas Index Cases for $30 million. The settlement does not include similar claims filed by individual plaintiffs in the Coordinated Gas Index Cases, which we continue to defend vigorously. In December 2006, the court granted final approval of the settlement and dismissed the class action claims. In July 2007, the remaining Coordinated Gas Index Cases were stayed pending a ruling on the appeals before the Ninth Circuit discussed above. Also in August 2006, we entered into an agreement to settle the class action claims by California natural gas re-sellers and co-generators (to the extent they purchased natural gas to generate electricity for re-sale) pending in Nevada federal court for $2.4 million. The court granted preliminary approval of this settlement in May 2007, which we funded shortly thereafter, and scheduled a final approval hearing in October 2007. Both settlements are without admission of wrongdoing, and Dynegy and West Coast Power continue to deny class plaintiffs’ allegations.

In the Alabama litigation, trial is currently scheduled for October 2007.

We are analyzing the remaining natural gas index cases and are vigorously defending against them. We cannot predict with certainty whether we will incur any liability in connection with these lawsuits. However, given the nature of the claims, an adverse result in any of these proceedings could have a material adverse effect on our financial condition, results of operations and cash flows.

California Market Litigation. We and various other power generators and marketers were defendants in numerous lawsuits alleging rate and market manipulation in California’s wholesale electricity market during the California energy crisis several years ago. The complaints generally alleged unfair, unlawful and deceptive trade practices in violation of the California Unfair Business Practices Act and sought injunctive relief, restitution and unspecified actual and treble damages. All of these cases have been dismissed on grounds of federal preemption except for one remaining action that is pending and fully briefed before the Ninth Circuit Court of Appeals.

We cannot predict with certainty whether we will incur any liability in connection with the remaining pending appeal; however, given the pattern of dismissal and success on appeal of related actions, we expect a similar outcome. Nonetheless, given the nature of this claim, an adverse result could have a material adverse effect on our financial condition, results of operations and cash flows.

Illinois Auction Complaints. On March 15, 2007, as amended on March 16, the Attorney General of the State of Illinois (the “IAG”) filed a complaint at FERC (the “IAG FERC Complaint”) against 16 electricity suppliers engaged in wholesale power sales, challenging the results of the Illinois reverse power procurement auction conducted in September 2006. The complaint alleges that the prices charged under supply contracts resulting from the auction process are not just and reasonable. The complaint also requests that FERC investigate purported price manipulation by the wholesale suppliers in the auction process. The complaint names DPM among the respondents. The public version of the complaint served upon DPM is heavily redacted resulting in substantial uncertainty regarding the specific allegations against DPM and the specific relief sought by the IAG against DPM. The ICC has intervened in the proceeding before FERC and has stated in its pleading that it has not found any evidence of collusive behavior or other anticompetitive actions by bidders in the Illinois Auction. DPM filed its motion to dismiss and answer the IAG FERC Complaint in June 2007. On July 3, 2007, the IAG filed a motion to suspend its complaint at FERC.

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Legislative leaders from the state of Illinois, including the Speaker of the House and the Senate President, announced a comprehensive transitional rate relief package for electric consumers on July 23, 2007. This rate relief package and related agreements are subject to passage of certain legislation.

As a part of the rate relief package, and subject to passage of certain legislation, we anticipate making payments of up to $25 million over a 29-month period. These payments will be contingent on certain conditions related to the absence of future electric rate and tax legislation in Illinois. We anticipate making payments of $7.5 million in 2007, $9.0 million in 2008 and $8.5 million in 2009. We recorded a $25 million expense in the second quarter of 2007 related to these payments, which is included in cost of sales on our unaudited condensed consolidated statement of operations. Our payment of $7.5 million in 2007 is to be used for funding of the Illinois Power Agency, which is to be created as part of Illinois’ comprehensive legislative package. Our expected payments for 2008 and 2009 will be made in monthly installments so long as Illinois does not impose an electric rate freeze or an additional tax on generators prior to December 2009, as further described in the rate relief package and related agreements. The monthly payments will be paid into an escrow account established to support rate relief activities for Ameren Illinois Utilities’ customers.

The rate relief package and related agreements, once effective, will result in motions to dismiss with prejudice being filed in several ongoing court and regulatory proceedings including the IAG FERC Complaint, appeals of the original orders adopting the auction process and the auction improvements case.

The legislation passed both chambers of the Illinois General Assembly and is currently awaiting action by the Governor.

Shortly after the IAG FERC Complaint was filed, two civil class action complaints against 21 wholesale electricity suppliers and utilities, including DPM, were filed in Illinois state court. The complaints largely mirror the IAG’s filing and seek unspecified actual and punitive damages. In late April 2007, the defendants filed notices of removal to federal court in both cases. In late June 2007, the defendants moved to dismiss plaintiffs’ claim on grounds of the filed rate doctrine and preemption. Briefing on defendants’ motion is expected to continue into the third quarter.

We believe that the claims of the IAG and the civil plaintiffs are without merit and we intend to defend against them vigorously. However, given the gravity of their claims, an adverse ruling in some or all of these proceedings could have a material adverse effect on our financial condition, results of operations and cash flows.

Danskammer State Pollutant Discharge Elimination System Permit. In January 2005, the New York State Department of Environmental Conservation (“NYSDEC”) issued a Draft SPDES Permit renewal for the Danskammer plant, and an adjudicatory hearing was scheduled for the fall of 2005. Three environmental groups sought to impose a permit requirement that the Danskammer plant install a closed cycle cooling system in order to reduce the volume of water withdrawn from the Hudson River, thus reducing aquatic organism mortality. The petitioners claim that only a closed cycle cooling system meets the Clean Water Act’s requirement that the cooling water intake structures reflect best technology available (“BTA”) for minimizing adverse environmental impacts.

A formal evidentiary hearing was held in November and December 2005. The Deputy Commissioner’s decision directing that the NYSDEC staff issue the revised Draft SPDES Permit was issued in May 2006. In June 2006, the NYSDEC issued the revised SPDES Permit with conditions generally favorable to us. While the revised SPDES Permit does not require installation of a closed cycle cooling system, it does require aquatic organism mortality reductions resulting from NYSDEC’s determination of BTA requirements under its regulations. In July 2006, two of the petitioners filed suit in the Supreme Court of the State of New York seeking to vacate the Deputy

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Commissioner’s decision and the revised Danskammer SPDES Permit. On March 26, 2007, the Court transferred the lawsuit to the Third Department Appellate Division. The case will now proceed as a normal appeal from a final agency decision and the decision will be based on whether there is substantial evidence in the record to support the agency decision. We believe that the decision of the Deputy Commissioner is well reasoned and will be affirmed. However, in the event the decision is not affirmed and we ultimately are required to install a closed cycle cooling system, this could have a material adverse effect on our financial condition, results of operations and cash flows.

Roseton State Pollutant Discharge Elimination System Permit. In April 2005, the NYSDEC issued to DNE a draft SPDES Permit renewal (the “Draft SPDES Permit”) for the Roseton plant. The Draft SPDES Permit requires the facility to actively manage its water intake to substantially reduce mortality of aquatic organisms.

In July 2005, a public hearing was held to receive comments on the Draft SPDES Permit. Three environmental organizations filed petitions for party status in the permit renewal proceeding. The petitioners are seeking to impose a permit requirement that the Roseton plant install a closed cycle cooling system in order to reduce the volume of water withdrawn from the Hudson River, thus reducing aquatic organism mortality. The petitioners claim that only a closed cycle cooling system meets the Clean Water Act’s requirement that the cooling water intake structures reflect the BTA for minimizing adverse environmental impacts. In September 2006, the administrative law judge issued a ruling admitting the petitioners to full party status and setting forth the issues to be adjudicated in the permit renewal hearing. Various holdings in the ruling have been appealed to the Commissioner of NYSDEC by DNE, NYSDEC staff, and the petitioners. We expect that the adjudicatory hearing on the Draft SPDES Permit will occur in 2007 or 2008. We believe that the petitioners’ claims are without merit, and we plan to oppose those claims vigorously. Given the high cost of installing a closed-cycle cooling system, an adverse result in this proceeding could have a material adverse effect on our financial condition, results of operations and cash flows.

Moss Landing National Pollutant Discharge Elimination System Permit. The California Regional Water Quality Control Board (“Water Board”) issued a NPDES permit for the Moss Landing Power Plant in October 2000 in connection with modernization of the plant and the California Energy Commission’s licensing of that project. A local environmental group, Voices of the Wetlands (“Petitioner”), sought review of the permit in Superior Court in Monterey County in July 2001 claiming that the permit is not supported by sufficient analysis of the best technology available (“BTA”) for cooling water intake structures as required under the Clean Water Act. Petitioner contends that the once-through, seawater-cooling system at Moss Landing should be replaced with a closed-cycle cooling system.

In July 2004, the Superior Court rejected Petitioner’s claims, holding that the Water Board had conducted a thorough and comprehensive BTA analysis in issuing the permit. This decision was appealed by Petitioner to California’s Sixth Appellate District. Briefing for the appeal was completed in November 2005, and the matter was recently set for oral argument on September 18, 2007.

We believe that Petitioner’s claims lack merit and we plan to oppose those claims vigorously. Given the high cost of installing a closed-cycle cooling system, an adverse result in this proceeding could have a material adverse effect on our financial condition, results of operation and cash flow.

Guarantees and Indemnifications

In the ordinary course of business, we routinely enter into contractual agreements that contain various representations, warranties, indemnifications and guarantees. Examples of such agreements include, but are not limited to, service agreements, equipment purchase agreements, engineering and technical service agreements, and procurement and construction contracts. Some agreements contain indemnities that cover the other party’s

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negligence or limit the other party’s liability with respect to third party claims, in which event we will effectively be indemnifying the other party. Virtually all such agreements contain representations or warranties that are covered by indemnifications against the losses incurred by the other parties in the event such representations and warranties are false. While there is always the possibility of a loss related to such representations, warranties, indemnifications and guarantees in our contractual agreements, and such loss could be significant, in most cases management considers the probability of loss to be remote.

WCP Indemnities. In connection with the sale of our 50% interest in West Coast Power to NRG on March 31, 2006, an agreement was executed to allocate responsibility for managing certain litigation and provide for certain indemnities with respect to such litigation. The agreement states that we will manage the Gas Index Pricing Litigation described above for which NRG could suffer a loss subsequent to the closing and that we would indemnify NRG for all costs or losses resulting from such litigation, as well as from other proceedings based on similar acts or omissions which formed the basis of such litigation. The agreement further states that we will manage the California Market Litigation described above for which NRG could suffer a loss subsequent to the closing, and that we and NRG would each be responsible for 50% of any costs or losses resulting from that power litigation, as well as from other proceedings based on similar acts or omissions which formed the basis of such litigation. The agreement provides that NRG will manage other active litigation and indemnify us for any resulting losses, subject to certain conditions. Maximum recourse under these matters is not limited by the agreement or by the passage of time with the exception of the California Department of Water Resources matter in which NRG has a specified indemnity obligation. The damages claimed by the various plaintiffs in these matters are unspecified as of June 30, 2007.

Targa Indemnities. During 2005, as part of our sale of DMSLP, we agreed to indemnify Targa against losses it may incur under indemnifications DMSLP provided to purchasers of certain assets, properties and businesses disposed of by DMSLP prior to our sale of DMSLP. We have incurred no significant expense under these prior indemnities and deem their value to be insignificant. We have recorded an accrual in association with the cleanup of groundwater contamination at the Breckenridge Gas Processing Plant. The indemnification provided by DMSLP to the purchaser of the plant has a limit of $5 million. We have also indemnified Targa for certain tax matters arising from periods prior to our sale of DMSLP. We have recorded a reserve associated with this indemnification.

Illinois Power Indemnities. As a condition of Dynegy’s 2004 sale of Illinois Power and its interest in Electric Energy Inc.’s plant in Joppa, Illinois, Dynegy provided indemnifications to third parties regarding environmental, tax, employee and other representations. These indemnifications are limited to a maximum recourse of $400 million. Additionally, Dynegy has indemnified third parties against losses resulting from possible adverse regulatory actions taken by the ICC that could prevent Illinois Power from recovering costs incurred in connection with purchased natural gas and investments in specified items. Although there is no limitation on Dynegy’s liability under this indemnity, its indemnity is limited to 50% of any such losses. On July 27, 2005, Dynegy made a payment of $8 million to Ameren in settlement of Ameren’s indemnification claims with respect to an ICC Order disallowing items relating to one of Illinois Power’s natural gas storage fields resulting in a negative revenue requirement impact to Ameren. In anticipation of similar cases, Dynegy recognized a pre-tax charge of $12 million in 2005. As anticipated, Dynegy paid Ameren for an additional amount disallowed in a similar ICC Order in the third quarter 2006. Furthermore, in July 2007, the ICC issued a similar Order, which, though still subject to the rehearing process, is expected to become final in August or September of this year. Dynegy has adjusted the amount reserved for the various ongoing cases in light of these and other developments in the cases. Further disallowances and other events which fall within the scope of the indemnity may still occur; however, Dynegy is not required to accrue a liability in connection with these indemnifications, as management cannot reasonably estimate a range of outcomes or at this time considers the probability of an adverse outcome as only reasonably possible. Dynegy intends to contest any proposed disallowances.

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For the Interim Periods Ended June 30, 2007 and 2006

Northern Natural and Other Indemnities. During 2003, as part of our sale of Northern Natural, the Rough and Hornsea natural gas storage facilities and certain natural gas liquids assets, we provided indemnities to third parties regarding environmental, tax, employee and other representations. Maximum recourse under these indemnities is limited to $209 million, $857 million and $28 million for the Northern Natural, Rough and Hornsea natural gas storage facilities and natural gas liquids assets, respectively. We also entered into similar indemnifications regarding environmental, tax, employee and other representations when completing other asset sales such as, but not limited to, Hackberry LNG Project, SouthStar Energy Services, various Canadian assets, Michigan Power, Oyster Creek, Hartwell, Commonwealth, Sherman, and Indian Basin. We have recorded reserves for existing environmental, tax and employee liabilities and have incurred no other expense relating to these indemnities.

Black Mountain. Through one of our subsidiaries, we hold a 50% ownership interest in Black Mountain (Nevada Cogeneration) (“Black Mountain”), in which our partner is a CUSA subsidiary. Black Mountain owns the Black Mountain power generation facility and has a power purchase agreement with a third party that extends through April 2023. In connection with the power purchase agreement, pursuant to which Black Mountain receives payments which decrease in amount over time, we agreed to guarantee 50% of certain payments that may be due to the power purchaser under a mechanism designed to protect it from early termination of the agreement. At June 30, 2007, if an event of default due to early termination had occurred under the terms of the mortgage on the facility entered into in connection with the power purchase agreement, we could have been required to pay the power purchaser approximately $63 million under the guarantee. While there is a question of interpretation regarding the existence of an obligation to make payments calculated under this mechanism upon the scheduled termination of the agreement, management does not expect that any such payments will be required.

Note 11—Regulatory Issues

We are subject to regulation by various federal, state and local agencies, including extensive rules and regulations governing transportation, transmission and sale of energy commodities as well as the discharge of materials into the environment or otherwise relating to environmental protection. Compliance with these regulations requires general and administrative, capital and operating expenditures including those related to monitoring, pollution control equipment, emission fees and permitting at various operating facilities and remediation obligations. The matters discussed below are material developments since the filing of our Forms 10-K. Please see Note 18—Regulatory Issues beginning on page F-53 and page F-40, respectively, of Dynegy’s and DHI’s Forms 10-K for further discussion.

Illinois Resource Procurement Auction. In January 2006, the ICC approved a reverse power procurement auction as the process by which utilities will procure power beginning in 2007. The auction occurred in September 2006, and we subsequently entered into two supplier forward contracts with subsidiaries of Ameren Corporation to provide capacity, energy and related services. There continue to be challenges to the auction process. Please see Note 10—Commitments and Contingencies—Illinois Auction Complaints for further discussion.

California Greenhouse Gas Regulation. The California Global Warming Solutions Act (“AB 32”), enacted in September 2006, became effective on January 1, 2007. This Act directs the California Air Resources Board (“CARB”) to develop a greenhouse gas control program that will reduce the state’s greenhouse gas emissions to their 1990 levels by 2020. CARB must establish the statewide greenhouse gas emissions cap by January 2008; must finalize regulations to achieve required emission reductions by January 2011; and, must begin implementation and enforcement of the regulatory program by January 2012.

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On October 30, 2006, the California Energy Commission (“CEC”) instituted a proceeding for establishing a greenhouse gases emission performance standard. This rulemaking implements Senate Bill No. 1368 which directs the CEC, in consultation with other state agencies, to establish performance standards for publicly owned utilities which restrict the rate of greenhouse gases emissions to that of combined-cycle natural gas baseload generation.

Although California’s comprehensive greenhouse gas control program will likely influence the development of federal and state programs, the structure and requirements have yet to be fully developed. While we cannot predict the potential impact of the California greenhouse gas program on our future financial condition, results of operations or cash flows, the program could have far-reaching and significant impacts on the energy industry.

Federal Greenhouse Gas Regulation. Despite a great deal of support in the energy industry for a comprehensive federal program, and numerous proposals in Congress, no proposal for the regulation of greenhouse gases which addresses the issue of global warming has been enacted. On April 2, 2007, the U. S. Supreme Court ruled in Massachusetts v. Environmental Protection Agency, a case involving regulation of carbon dioxide (“CO₂”) emissions of motor vehicles. The Environmental Protection Agency (“EPA”) had resisted incorporating requirements for control of CO₂ emissions based on its conclusion that CO₂ was not a “pollutant” under the Clean Air Act. The Court ruled that CO₂ is a pollutant subject to regulation under the Clean Air Act and that the EPA has a duty to determine whether CO₂ emissions contribute to climate change. This decision , together with increasing state and federal legislative and regulatory initiatives and other related activities, will likely lead to regulation of greenhouse gasses. The precise timing and impact on us and the rest of the power generation industry cannot yet be determined.

Note 12—Employee Compensation, Savings and Pension Plans

We have various defined benefit pension plans and post-retirement benefit plans in which our past and present employees participate, which are more fully described in Note 20—Employee Compensation, Savings and Pension Plans beginning on page F-61 of Dynegy’s Form 10-K, and Note 18—Employee Compensation, Savings and Pension Plans beginning on page F-45 of DHI’s Form 10-K.

Components of Net Periodic Benefit Cost. The components of net periodic benefit cost were:


	Pension Benefits						Other Benefits
	Quarter Ended June 30,
	2007			2006			2007		2006
	(in millions)
Service cost benefits earned during period	$	3		$	3		$	—	$	1
Interest cost on projected benefit obligation		2			3			1		1
Expected return on plan assets		(3	)		(3	)		—		—
Recognized net actuarial loss		—			—			1		—

Total net periodic benefit cost	$	2		$	3		$	2	$	2


	Pension Benefits						Other Benefits
	Six Months Ended June 30,
	2007			2006			2007		2006
	(in millions)
Service cost benefits earned during period	$	5		$	5		$	1	$	2
Interest cost on projected benefit obligation		5			5			2		2
Expected return on plan assets		(6	)		(5	)		—		—
Recognized net actuarial loss		1			1			1		—

Net periodic benefit cost	$	5		$	6		$	4	$	4
Additional cost due to curtailment		—			2			—		—

Total net periodic benefit cost	$	5		$	8		$	4	$	4

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Exchange Transaction with Chairman and CEO. On March 17, 2006, Dynegy entered into an exchange transaction with Dynegy’s Chairman and CEO. Under the terms of the transaction, the purpose of which was to address uncertainties created by proposed regulations issued in late 2005 pursuant to Section 409A of the Internal Revenue Code (the “Code”), Dynegy cancelled all of the 2,378,605 stock options then held by Dynegy’s Chairman and CEO. As consideration for canceling these stock options, Dynegy granted its Chairman and CEO 967,707 stock options at an exercise price of $4.88, which equaled the closing price of Dynegy’s Class A common stock on the date of grant, and DHI made a cash payment to him of approximately $6 million on January 15, 2007 based on the in-the-money value of the vested stock options that were cancelled.

Contributions. During the six months ended June 30, 2007, we made approximately $1 million in contributions to our pension plans. We expect to make contributions of approximately $12 million to our pension plans and $1 million to other benefit plans in the third or fourth quarter 2007.

Note 13—Income Taxes

Effective Tax Rate. We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income or loss, except for significant unusual or extraordinary transactions. Income taxes for significant unusual or extraordinary transactions are computed and recorded in the period that the specific transaction occurs. Dynegy’s income taxes included in continuing operations were as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
	(in millions, except rates)
Income tax (expense) benefit	$	(30	)	$	117		$	(36	)	$	109
Effective tax rate		31	%		36	%		30	%		35	%

For the three and six months ended June 30, 2007, Dynegy’s overall effective tax rate on continuing operations was different than the statutory rate of 35% due primarily to state income taxes and adjustments to Dynegy’s reserve for uncertain tax positions. As a result of the Merger Agreement, our effective state tax rate increased primarily as a result of the higher state tax rates in the states in which the LS assets are located. This increase was more than offset by the impact of decreases in the New York state income tax rate and the Texas margin tax credit rate during the three months ended June 30, 2007.

DHI’s income taxes included in continuing operations were as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
	(in millions, except rates)
Income tax (expense) benefit	$	(21	)	$	94		$	(32	)	$	89
Effective tax rate		20	%		34	%		23	%		34	%

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For the Interim Periods Ended June 30, 2007 and 2006

For the three and six months ended June 30, 2007, DHI’s overall effective tax rate on continuing operations was different than the statutory rate of 35% due primarily to state income taxes and adjustments to DHI’s reserve for uncertain tax positions. As a result of the Merger Agreement, our effective state tax rate increased primarily as a result of the higher state tax rates in the states in which the LS assets are located. This increase was more than offset by the impact of decreases in the New York state income tax rate and the Texas margin tax credit rate during the six months ended June 30, 2007.

Dynegy and DHI recorded a $7 million and $13 million decrease, respectively, to their accumulated deficits as of January 1, 2007 to reflect the cumulative effect of adopting FIN No. 48. Please see Note 1—Accounting Policies—Accounting Principles Adopted—FIN No. 48 for further discussion.

Note 14—Segment Information

We report results of our power generation business in the following segments: (i) GEN-MW, (ii) GEN-NE and (iii) GEN-WE. Following the completion of the Merger Agreement in April 2007, our previously named South segment (“GEN-SO”) has been renamed the GEN-WE segment and the power generation facilities located in California and Arizona acquired through the Merger Agreement are included in this segment. The Kendall, Ontelaunee and Plum Point power generation facilities acquired through the Merger Agreement are included in GEN-MW, and the Casco Bay and Bridgeport power generation facilities acquired through the Merger Agreement are included in GEN-NE. We continue to separately report the results of our CRM business. Results associated with our former NGL segment are included in discontinued operations in Other and Eliminations due to the sale of this business. Our unaudited condensed consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization. Because of the diversity among their respective operations, we report the results of each business as a separate segment in our unaudited condensed consolidated financial statements.

Pursuant to EITF Issue 02-03, all gains and losses on third party energy trading contracts in the CRM segment, whether realized or unrealized, are presented net in the consolidated statements of operations. For the purpose of the segment data presented below, intersegment transactions between CRM and our other segments are presented net in CRM intersegment revenues but are presented gross in the intersegment revenues of our other segments, as the activities of our other segments are not subject to the net presentation requirements contained in EITF Issue 02-03. If transactions between CRM and our other segments result in a net intersegment purchase by CRM, the net intersegment purchases and sales are presented as negative revenues in CRM intersegment revenues. In addition, intersegment hedging activities are presented net pursuant to SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133).

In the second quarter 2007, we discontinued the use of hedge accounting for certain derivative transactions affecting the GEN-MW, GEN-NE and GEN-WE segments. The operating results presented herein reflect the changes in market values of derivative instruments entered into by each of these segments. Please see Note 5—Risk Management Activities for further discussion.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

Reportable segment information for Dynegy, including intercompany transactions accounted for at prevailing market rates, for the three and six months ended June 30, 2007 and 2006 is presented below:

Dynegy’s Segment Data for the Three Months Ended June 30, 2007

(in millions)


	Power Generation									CRM			Other and Eliminations			Total
	GEN-MW			GEN-NE			GEN-WE			CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	406		$	226		$	145		$	(3	)	$	—		$	774
Other		—			53			—			1			—			54

Total revenues	$	406		$	279		$	145		$	(2	)	$	—		$	828

Depreciation and amortization	$	(50	)	$	(12	)	$	(23	)	$	—		$	(3	)	$	(88	)
Operating income (loss)	$	160		$	54		$	(12	)	$	31		$	(51	)	$	182

Losses from unconsolidated investments		—			—			—			—			(2	)		(2	)
Other items, net		(9	)		—			—			(3	)		13			1
Interest expense																	(84	)

Income from continuing operations before income taxes																	97
Income tax expense																	(30	)

Income from continuing operations																	67
Income from discontinued operations, net of taxes																	9

Net income																$	76

Identifiable assets:
Domestic	$	6,280		$	1,762		$	3,326		$	312		$	1,508		$	13,188
Other		—			21			7			108			—			136

Total	$	6,280		$	1,783		$	3,333		$	420		$	1,508		$	13,324

Unconsolidated investments	$	—		$	—		$	—		$	—		$	86		$	86

Capital expenditures and investments in unconsolidated affiliates	$	(92	)	$	(16	)	$	(6	)	$	—		$	(10	)	$	(124	)

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

Dynegy’s Segment Data for the Three Months Ended June 30, 2006

(in millions)


	Power Generation									CRM			Other and Eliminations			Total
	GEN-MW			GEN-NE			GEN-WE			CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	228		$	95		$	8		$	9		$	—		$	340
Other		—			31			—			8			—			39

		228			126			8			17			—			379
Intersegment revenues		—			(1	)		—			1			—			—

Total revenues	$	228		$	125		$	8		$	18		$	—		$	379

Depreciation and amortization	$	(43	)	$	(6	)	$	(3	)	$	—		$	(2	)	$	(54	)
Impairment and other charges		—			—			(9	)		—			—			(9	)

Operating income (loss)	$	71		$	—		$	(9	)	$	(8	)	$	(34	)	$	20
Other items, net		—			2			1			(2	)		9			10
Interest expense																	(354	)

Loss from continuing operations before income taxes																	(324	)
Income tax benefit																	117

Loss from continuing operations																	(207	)
Income from discontinued operations, net of taxes																	—

Net loss																$	(207	)

Identifiable assets:
Domestic	$	5,051		$	1,349		$	552		$	462		$	158		$	7,572
Other		—			16			2			99			—			117

Total	$	5,051		$	1,365		$	554		$	561		$	158		$	7,689

Unconsolidated investments	$	—		$	—		$	4		$	—		$	—		$	4

Capital expenditures	$	(25	)	$	(4	)	$	(9	)	$	—		$	(3	)	$	(41	)

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

Dynegy’s Segment Data for the Six Months Ended June 30, 2007

(in millions)


	Power Generation
	GEN-MW			GEN-NE			GEN-WE			CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	678		$	426		$	145		$	6		$	—		$	1,255
Other		—			77			—			1			—			78

Total revenues	$	678		$	503		$	145		$	7		$	—		$	1,333

Depreciation and amortization	$	(92	)	$	(18	)	$	(24	)	$	—		$	(6	)	$	(140	)
Operating income (loss)	$	260		$	96		$	(14	)	$	29		$	(108	)	$	263
Losses from unconsolidated investments		—			—			—			—			(2	)		(2	)
Other items, net		(9	)		—			—			(3	)		21			9
Interest expense																	(151	)

Income from continuing operations before income taxes																	119
Income tax expense																	(36	)

Income from continuing operations																	83
Income from discontinued operations, net of taxes																	7

Net income																$	90

Identifiable assets:
Domestic	$	6,280		$	1,762		$	3,326		$	312		$	1,508		$	13,188
Other		—			21			7			108			—			136

Total	$	6,280		$	1,783		$	3,333		$	420		$	1,508		$	13,324

Unconsolidated investments	$	—		$	—		$	—		$	—		$	86		$	86
Capital expenditures and investments in unconsolidated affiliates	$	(115	)	$	(19	)	$	(11	)	$	—		$	(13	)	$	(158	)

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

Dynegy’s Segment Data for the Six Months Ended June 30, 2006

(in millions)


	Power Generation
	GEN-MW			GEN-NE			GEN-WE			CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	484		$	228		$	59		$	49		$	—		$	820
Other		—			91			—			8			—			99

		484			319			59			57			—			919
Intersegment revenues		—			(2	)		—			2			—			—

Total revenues	$	484		$	317		$	59		$	59		$	—		$	919

Depreciation and amortization	$	(83	)	$	(12	)	$	(5	)	$	—		$	(10	)	$	(110	)
Impairment and other charges		—			—			(9	)		—			(2	)		(11	)
Operating income (loss)	$	169		$	26		$	(8	)	$	6		$	(81	)	$	112
Earnings from unconsolidated investments		—			—			2			—			—			2
Other items, net		—			4			1			(1	)		26			30
Interest expense																	(452	)

Loss from continuing operations before income taxes																	(308	)
Income tax benefit																	109

Loss from continuing operations																	(199	)
Loss from discontinued operations, net of taxes																	(8	)
Cumulative effect of change in accounting principle, net of taxes																	1

Net loss																$	(206	)

Identifiable assets:
Domestic	$	5,051		$	1,349		$	552		$	462		$	158		$	7,572
Other		—			16			2			99			—			117

Total	$	5,051		$	1,365		$	554		$	561		$	158		$	7,689

Unconsolidated investments	$	—		$	—		$	4		$	—		$	—		$	4
Capital expenditures	$	(36	)	$	(7	)	$	(12	)	$	—		$	(4	)	$	(59	)

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

Reportable segment information for DHI, including intercompany transactions accounted for at prevailing market rates, for the three and six months ended June 30, 2007 and 2006 is presented below:

DHI’s Segment Data for the Three Months Ended June 30, 2007

(in millions)


	Power Generation
	GEN-MW			GEN-NE			GEN-WE			CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	406		$	226		$	145		$	(3	)	$	—		$	774
Other		—			53			—			1			—			54

Total revenues	$	406		$	279		$	145		$	(2	)	$	—		$	828

Depreciation and amortization	$	(50	)	$	(12	)	$	(23	)	$	—		$	(3	)	$	(88	)
Operating income (loss)	$	160		$	54		$	(12	)	$	31		$	(49	)	$	184
Other items, net		(9	)		—			—			(3	)		15			3
Interest expense																	(84	)

Income from continuing operations before income taxes																	103
Income tax expense																	(21	)

Income from continuing operations																	82
Income from discontinued operations, net of taxes																	8

Net income																$	90

Identifiable assets:
Domestic	$	6,280		$	1,762		$	3,331		$	337		$	2,105		$	13,815
Other		—			21			—			83			—			104

Total	$	6,280		$	1,783		$	3,331		$	420		$	2,105		$	13,919

Capital expenditures	$	(92	)	$	(16	)	$	(6	)	$	—		$	(5	)	$	(119	)

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

DHI’s Segment Data for the Three Months Ended June 30, 2006

(in millions)


	Power Generation
	GEN-MW			GEN-NE			GEN-WE			CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	228		$	95		$	8		$	9		$	—		$	340
Other		—			31			—			8			—			39

		228			126			8			17			—			379
Intersegment revenues		—			(1	)		—			1			—			—

Total revenues	$	228		$	125		$	8		$	18		$	—		$	379

Depreciation and amortization	$	(43	)	$	(6	)	$	(3	)	$	—		$	(2	)	$	(54	)
Impairment and other charges		—			—			(9	)		—			—			(9	)
Operating income (loss)	$	71		$	—		$	(9	)	$	(8	)	$	(33	)	$	21
Other items, net		—			2			1			(2	)		9			10
Interest expense																	(305	)

Loss from continuing operations before income taxes																	(274	)
Income tax benefit																	94

Loss from continuing operations																	(180	)
Loss from discontinued operations, net of taxes																	(1	)

Net loss																$	(181	)

Identifiable assets:
Domestic	$	4,911		$	1,303		$	692		$	567		$	725		$	8,198
Other		—			16			—			64			—			80

Total	$	4,911		$	1,319		$	692		$	631		$	725		$	8,278

Unconsolidated investments	$	—		$	—		$	4		$	—		$	—		$	4
Capital expenditures	$	(25	)	$	(4	)	$	(9	)	$	—		$	(3	)	$	(41	)

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

DHI’s Segment Data for the Six Months Ended June 30, 2007

(in millions)


	Power Generation									CRM			Other and Eliminations			Total
	GEN-MW			GEN-NE			GEN-WE			CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	678		$	426		$	145		$	6		$	—		$	1,255
Other		—			77			—			1			—			78

Total revenues	$	678		$	503		$	145		$	7		$	—		$	1,333

Depreciation and amortization	$	(92	)	$	(18	)	$	(24	)	$	—		$	(6	)	$	(140	)

Operating income (loss)	$	260		$	96		$	(14	)	$	29		$	(89	)	$	282

Other items, net		(9	)		—			—			(3	)		19			7
Interest expense																	(151	)

Income from continuing operations before income taxes																	138
Income tax expense																	(32	)

Income from continuing operations																	106
Income from discontinued operations, net of taxes																	6

Net income loss																$	112

Identifiable assets:
Domestic	$	6,280		$	1,762		$	3,331		$	337		$	2,105		$	13,815
Other		—			21			—			83			—			104

Total	$	6,280		$	1,783		$	3,331		$	420		$	2,105		$	13,919

Capital expenditures	$	(115	)	$	(19	)	$	(11	)	$	—		$	(8	)	$	(153	)

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

DHI’s Segment Data for the Six Months Ended June 30, 2006

(in millions)


	Power Generation									CRM			Other and Eliminations			Total
	GEN-MW			GEN-NE			GEN-WE			CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	484		$	228		$	59		$	49		$	—		$	820
Other		—			91			—			8			—			99

		484			319			59			57			—			919
Intersegment revenues		—			(2	)		—			2			—			—

Total revenues	$	484		$	317		$	59		$	59		$	—		$	919

Depreciation and amortization	$	(83	)	$	(12	)	$	(5	)	$	—		$	(10	)	$	(110	)
Impairment and other charges		—			—			(9	)		—			(2	)		(11	)
Operating income (loss)	$	169		$	26		$	(8	)	$	6		$	(80	)	$	113
Earnings from unconsolidated investments		—			—			2			—			—			2
Other items, net		—			4			1			(1	)		23			27
Interest expense																	(400	)

Loss from continuing operations before income taxes																	(258	)
Income tax benefit																	89

Loss from continuing operations																	(169	)
Loss from discontinued operations, net of taxes																	(9	)

Net loss																$	(178	)

Identifiable assets:
Domestic	$	4,911		$	1,303		$	692		$	567		$	725		$	8,198
Other		—			16			—			64			—			80

Total	$	4,911		$	1,319		$	692		$	631		$	725		$	8,278

Unconsolidated investments	$	—		$	—		$	4		$	—		$	—		$	4

Capital expenditures	$	(36	)	$	(7	)	$	(12	)	$	—		$	(4	)	$	(59	)

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2007 and 2006

Note 15—DHI Related Party Transactions

On March 30, 2007, DHI made a dividend payment of $50 million to Dynegy. In April 2007, DHI made dividends of $275 million and $17 million to Dynegy.

Note 16—Subsequent Events

In July 2007, we entered into agreements with various parties to make payments of up to $25 million to support a comprehensive rate relief package for Illinois electric consumers. These agreements are subject to the passage of certain related legislation, which currently awaits approval from the Illinois Governor. Please see Note 10—Commitments and Contingencies—Illinois Auction Complaints for further discussion.

On August 1, 2007, we completed the sale of our interest in the CoGen Lyondell power generation facility to EnergyCo. for approximately $470 million. Please see Note 3—GEN-WE Discontinued Operations—CoGen Lyondell for further discussion.

On August 6, 2007, we repaid the $275 million of borrowings we made on our Revolver plus accrued and unpaid interest to that date.

On August 8, 2007, we gave notice to redeem all of our remaining 2010 Notes, at a redemption price of 104.938% of the principal amount, plus accrued and unpaid interest to the redemption date.

DYNEGY INC. and DYNEGY HOLDINGS INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

For the Interim Periods Ended June 30, 2007 and 2006

Item 2—MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—DYNEGY INC. AND DYNEGY HOLDINGS INC.

The following discussion should be read together with the unaudited condensed consolidated financial statements and the notes thereto included in this report and with the audited consolidated financial statements and the notes thereto included in our Forms 10-K.

In April 2007, Dynegy contributed to DHI its interest in New York Holdings. This contribution was accounted for as a transaction between entities under common control. As such, the assets and liabilities of New York Holdings were recorded by DHI at Dynegy’s historical cost on the acquisition date. This management’s discussion and analysis of financial condition and results of operations included herein with respect to DHI reflects the contribution as though DHI had owned New York Holdings in all periods presented.

General

We are holding companies and conduct substantially all of our business operations through our subsidiaries. Our current business operations are focused primarily on the power generation sector of the energy industry. We report the results of our power generation business as three separate segments in our consolidated financial statements: (1) the Midwest segment (“GEN-MW”); (2) the Northeast segment (“GEN-NE”); and (3) the West segment (“GEN-WE”). We also separately report results of our CRM business, which primarily consists of our legacy physical gas supply contracts and gas transportation contracts and remaining legacy power and emission trading positions that remain from the third-party trading business that was substantially exited in 2002. Because of the diversity among their respective operations, we report the results of each business as a separate segment in our consolidated financial statements. Our unaudited condensed consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization. In connection with the Merger Agreement discussed in Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions, our previously named South segment (“GEN-SO”) has been renamed GEN-WE and the power generation facilities located in California and Arizona acquired through the Merger Agreement are included in this segment. The Kendall and Ontelaunee power generation facilities acquired through the Merger Agreement are included in GEN-MW, and the Casco Bay and Bridgeport power generation facilities acquired through the Merger Agreement are included in GEN-NE.

In addition to our operating generation facilities, we own an approximate 40% undivided interest in Plum Point, a new 665 MW coal-fired plant under construction in Arkansas which is included in GEN-MW. Finally, through its interest in DLS Power Holdings, Dynegy also owns a 50% interest in a portfolio of greenfield development projects totaling more than 7,600 MW of generating capacity and repowering and/or expansion opportunities representing approximately 2,500 MW of generating capacity which is included in Other.

Recent Developments

LS Power. On September 14, 2006, Dynegy entered into the Merger Agreement with the LS Contributing Entities, Merger Sub and Dynegy Illinois to, among other transactions, combine the LS Contributing Entities’ operating generation portfolio with Dynegy’s generation assets, acquire a 50 percent ownership interest in a development joint venture with LS Associates and merge Merger Sub with and into Dynegy Illinois pursuant to the Merger. On March 29, 2007, at a special meeting of the shareholders of Dynegy Illinois, the shareholders of Dynegy Illinois adopted the Merger Agreement and approved the Merger.

Pursuant to the transactions with the LS Contributing Entities contemplated by the Merger Agreement, which were completed on April 2, 2007, the LS Contributing Entities received 340 million shares of Dynegy’s Class B common stock (which are convertible, under the circumstances described in Dynegy’s amended and restated certificate of incorporation, into shares of Dynegy’s Class A common stock), $100 million in cash and a promissory note in the aggregate principal amount of $275 million (which was simultaneously issued and repaid in full without interest or prepayment penalty) in exchange for their contribution of their entire operating generation portfolio and a 50 percent interest in each of DLS Power Holdings and DLS Power Development (together comprising the development joint venture with LS Associates). Dynegy also, via its indirect wholly owned subsidiary Griffith Holdings, LLC, simultaneously issued to the LS Contributing Entities, and repaid in full without interest or prepayment penalty and cancelled, an additional $70 million of project-related debt (the “Griffith Debt”) in connection with the completion of the Merger Agreement transactions. Dynegy also assumed approximately $1.9 billion in debt from the LS Contributing Entities, and utilized $100 million of cash on hand and borrowings by DHI (and subsequent permitted distributions to Dynegy) of (i) an aggregate $275 million under the Revolving Facility (to repay the above-mentioned promissory note) and (ii) an aggregate $70 million under the new Term Loan B (to repay the above-mentioned project-related debt) in connection with the completion of the Merger Agreement.

Pursuant to the Merger, which was also completed on April 2, 2007, Merger Sub, Dynegy’s then-wholly owned subsidiary, merged with and into Dynegy Illinois. As a result of the Merger, Dynegy Illinois became Dynegy’s wholly owned subsidiary, the then-shareholders of Dynegy Illinois became Dynegy’s stockholders and each Dynegy Illinois shareholder, including CUSA (Dynegy Illinois’ then-largest shareholder), received one share of Dynegy’s Class A common stock for each share of Class A common stock or Class B common stock of Dynegy Illinois held by it.

As part of the transactions contemplated by the Merger Agreement, LS Associates transferred its interests in certain power generation development projects to DLS Power Holdings, and contributed 50% of the membership interests in DLS Power Holdings to Dynegy. In addition, immediately after the completion of the Merger, LS Associates and Dynegy each contributed $5 million to DLS Power Holdings as their initial capital contributions, and also contributed their respective interests in certain additional power generation development projects to DLS Power Holdings. LS Associates and Dynegy also each now own 50% of the membership interests in DLS Power Development.

In addition, in connection with the completion of the Merger and the other transactions contemplated by the Merger Agreement, Dynegy Acquisition, Inc.’s name was changed to Dynegy Inc. Please see Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions for further discussion.

Sithe Contribution. In April 2007, Dynegy Illinois contributed to DHI all of its interest in New York Holdings, together with its indirect interest in the subsidiaries of New York Holdings. New York Holdings, together with its wholly owned subsidiaries, owns various assets in the Northeast, which we commonly refer to as the “Sithe Assets”. The Sithe Assets primarily consist of the Independence generation facility, a 1,064 MW facility located in Scriba, New York, which Dynegy Illinois acquired in January 2005. As a result of the contribution, DHI’s Sithe toll has now become an intercompany agreement in DHI’s GEN-NE segment. The Sithe Assets contributed to DHI also include four hydroelectric generation facilities in Pennsylvania. Please read Note 7—Variable Interest Entities for further information.

Fifth Amended and Restated Credit Facility. On April 2, 2007, we entered into the Fifth Amended and Restated Credit Facility which amended DHI’s credit facility (the Fourth Amended and Restated Credit Facility, which was last amended on July 11, 2006) by increasing the amount of the existing $470 million revolving credit facility (the “Revolving Facility”) to $850 million, increasing the amount of the existing $200 million term letter of credit facility (the “Term L/C Facility”) to $400 million and adding a $70 million senior secured term loan facility (“Term Loan B”). On May 24, 2007, we entered into an Amendment No. 1, dated as of May 24, 2007 (the “Credit

Agreement Amendment”), to the Fifth Amended and Restated Credit Facility. The Credit Agreement Amendment amended the Fifth Amended and Restated Credit Facility by increasing the amount of the existing $850 million Revolving Facility to $1.15 billion and increasing the amount of the existing $400 million term letter of the Term L/C Facility to $850 million; the Credit Agreement Amendment did not affect the existing $70 million senior secured Term Loan B under the Fifth Amended and Restated Credit Facility. The Credit Agreement Amendment also amended a pro forma leverage ratio requirement in the Fifth Amended and Restated Credit Facility to allow DHI to issue the Notes (as defined below). Please see Note 8—Debt—Fifth Amended and Restated Credit Facility for further discussion.

Senior Unsecured Bond Offering. On May 24, 2007, DHI issued $1.1 billion aggregate principal amount of its 2019 Notes and $550 million aggregate principal amount of its 2015 Notes pursuant to the terms of a purchase agreement, dated as of May 17, 2007, by and among DHI and the Purchasers. DHI used the net proceeds from the sale of the Notes to repay a portion of the debt assumed in the Merger Agreement with LS Power. Please see Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions and Note 8—Debt—Senior Unsecured Notes offering for further discussion.

CoGen Lyondell Sale. On August 1, 2007, we completed our sale of our CoGen Lyondell power generation facility for approximately $470 million to EnergyCo., LLC (“EnergyCo.”), a joint venture between PNM Resources and a subsidiary of Cascade Investment, LLC. We expect to record an estimated $200 million gain related to the sale of the asset in the third quarter 2007.

Illinois Rate Relief. Legislative leaders from the state of Illinois, including the Speaker of the House and the Senate President, announced a comprehensive transitional rate relief package for electric consumers on July 23, 2007. The expected program, once effective, is expected to provide approximately $1 billion to help fund a new power procurement agency and provide assistance to utility customers in Illinois.

As a part of this rate relief package, and subject to passage of certain legislation, we anticipate making payments of up to $25 million over a 29-month period. These payments will be contingent on certain conditions related to the absence of future electric rate and tax legislation in Illinois. We anticipate making payments of $7.5 million in 2007, $9.0 million in 2008 and $8.5 million in 2009. Our payment of $7.5 million in 2007 is to be used as funding for the Illinois Power Agency, which is to be created as part of Illinois’ comprehensive legislative package. Our expected payments for 2008 and 2009 will be made in monthly installments, provided that if at any time prior to December 2009, as further described in the rate relief package and related agreements, Illinois imposes an electric rate freeze or imposes an additional tax on generators, our obligations to make the monthly payments will cease. The monthly payments will be paid into an escrow account established to support rate relief activities for Ameren Illinois Utilities’ customers. The rate relief package and related agreements, once effective, will result in motions to dismiss several ongoing court and regulatory cases surrounding the 2006 Illinois reverse power procurement auction. We recorded a second quarter 2007 pre-tax charge of $25 million, included as a cost of sales on our unaudited condensed consolidated statements of operations. Please read Note 10—Commitments and Contingencies—Illinois Auction Complaints for further discussion.

We expect that the contracts originally entered into by DPM and the Ameren Illinois Utilities as a result of the auction will remain in place following the effectiveness of the rate relief package and related agreements.

LIQUIDITY AND CAPITAL RESOURCES

Overview

In this section, we describe our liquidity and capital requirements and our internal and external liquidity and capital resources. Our liquidity and capital requirements are primarily a function of our debt maturities and debt service requirements, collateral requirements, fixed capacity payments and contractual obligations, capital expenditures, legal settlements and working capital needs. Examples of working capital needs include prepayments or cash collateral associated with purchases of commodities, particularly natural gas and coal, facility maintenance costs (including required environmental expenditures) and other costs such as payroll. Our liquidity and capital resources are primarily derived from cash flows from operations, cash on hand, borrowings under our financing agreements, asset sale proceeds and proceeds from capital market transactions to the extent we engage in these activities.

Debt Obligations

On April 2, 2007, in connection with the completion of the transactions contemplated by the Merger Agreement, an aggregate $275 million under the Revolving Facility, an aggregate $400 million under the Term L/C Facility (with the proceeds placed in a collateral account to support the issuance of letters of credit) and an aggregate $70 million under Term Loan B (representing all available borrowings under Term Loan B) were drawn. On May 24, 2007, we entered into the Credit Agreement Amendment. The Credit Agreement Amendment amended the Fifth Amended and Restated Credit Facility by increasing the amount of the existing $850 million Revolving Facility to $1.15 billion and increasing the amount of the existing $400 million term letter of the Term L/C Facility to $850 million; the Credit Agreement Amendment did not affect the Term Loan B. The Credit Agreement Amendment also amended a pro forma leverage ratio requirement in the Fifth Amended and Restated Credit Facility to allow DHI to issue the Notes. Please read Note 8—Debt—Fifth Amended and Restated Credit Facility for further discussion.

On April 2, 2007, we assumed approximately $1.9 billion of debt upon completion of the Merger Agreement. Please see Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions for further discussion. On May 24, 2007, DHI issued $1.1 billion aggregate principal amount of its 2019 Notes and $550 million aggregate principal amount of its 2015 Notes. DHI used the net proceeds from the sale of the Notes to repay a portion of the debt assumed in the Merger Agreement with LS Power. Please see Note 8—Debt—Senior Secured Notes for further discussion.

Collateral Postings

We continue to use a significant portion of our capital resources, in the form of cash and letters of credit, to satisfy counterparty collateral demands. These counterparty collateral demands reflect our non-investment grade credit ratings and counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors. The following table summarizes our consolidated collateral postings to third parties by business at August 2, 2007, June 30, 2007 and December 31, 2006:


	August 2, 2007		June 30, 2007		December 31, 2006
	(in millions)
By Business:
Generation	$	859	$	901	$	134
Customer Risk Management		63		49		54
Other		192		192		7

Total	$	1,114	$	1,142	$	195

By Type:
Cash (1)	$	53	$	51	$	38
Letters of Credit		1,061		1,091		157

Total	$	1,114	$	1,142	$	195

(1)	Cash collateral consists of either cash deposits to cover physical deliveries or liabilities on mark-to-market positions or prepayments for commodities or services that are in advance of normal payment terms.

The significant increase in collateral postings from December 31, 2006 to June 30, 2007 relates to higher prices for our legacy collateral postings and an increase of approximately $700 million due to the completion of the Merger Agreement and incorporation of the letters of credit postings required by the LS Contributing Entities. The $700 million is comprised of the following: approximately $325 million relating to hedging activities; approximately $130 million of development requirements; approximately $100 million as required under LTSAs and EMAs; approximately $90 million for environmental related requirements; and approximately $50 million of collateral requirements under transport and transmission agreements. There was also an addition of an $83 million letter of credit posted to satisfy the Sithe debt service reserve fund requirements that was previously funded with restricted cash.

Going forward, we expect counterparties’ collateral demands to continue to reflect changes in commodity prices, including seasonal changes in weather-related demand, as well as their views of our creditworthiness. We believe that we have sufficient capital resources to satisfy counterparties’ collateral demands, including those for which no collateral is currently posted, for the foreseeable future.

Tax Attributes

For accounting purposes, at January 1, 2007, Dynegy’s NOL deferred tax asset attributable to our previously incurred federal NOL carry-forwards was valued at approximately $695 million. These NOL carry-forwards will begin to expire in the year 2022. As a result of the application of the provisions of Section 382 of the Internal Revenue Code, when CUSA sold its shares of Dynegy’s class A common stock, Dynegy incurred an ownership change that established an annual limitation on the usage of our NOL carry-forwards. The limitation is based in part on the market value of Dynegy’s stock at the time of the ownership change and the then-prevailing interest rate and in part on certain built-in gains recognized in a particular taxable year.

The magnitude of the limitation and its effect on us is difficult to assess and may fluctuate depending on the amount of recognized built-in gains in a particular taxable year. However, we do not expect that the ownership change that occurred will have a material impact on Dynegy’s tax liability, because of the application of the built-in gain provisions of Section 382. The ultimate realization of Dynegy’s NOL carry-forwards will be affected, in part, by the tax law in effect at the time of realization.

Disclosure of Contractual Obligations and Contingent Financial Commitments

We have incurred various contractual obligations and financial commitments in the normal course of our operations and financing activities. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities. Contingent financial commitments represent obligations that become payable only if certain pre-defined events occur, such as financial guarantees.

Our contractual obligations and contingent financial commitments have changed since December 31, 2006. On April 2, 2007, in conjunction with the completion of the Merger Agreement, we assumed approximately $1 billion of contractual obligations in addition to the long-term debt assumed. These obligations primarily relate to interconnection, operations and maintenance, long term service, and gas transportation agreements. Further, upon completion of the Merger Agreement, our obligations under our power tolling arrangement related to the Kendall facility became an intercompany obligation. Please see Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions for further discussion. On May 24, 2007, we completed a $1.65 billion offering of senior unsecured notes. Please also read Note 8—Debt for a discussion of changes in our debt obligations.

As of June 30, 2007, there were no other material changes to our contractual obligations and contingent financial commitments since December 31, 2006.

Dividends on Common Stock

Dividend payments on Dynegy’s common stock are at the discretion of Dynegy’s Board of Directors. Dynegy did not declare or pay a dividend on its common stock for the second quarter 2007, and does not foresee a declaration of dividends in the near term.

Internal Liquidity Sources

Our primary internal liquidity sources are cash flows from operations, cash on hand and available capacity under our Fifth Amended and Restated Credit Facility, as amended, which is scheduled to mature in April 2012.

Current Liquidity. The following table summarizes our consolidated revolver capacity and liquidity position at August 2, 2007, June 30, 2007 and December 31, 2006:


	August 2, 2007			June 30, 2007 (1)			December 31, 2006
	(in millions)
Revolver capacity	$	1,150		$	1,150		$	470
Borrowings against revolver capacity		(275	)		(275	)		—
Term letter of credit capacity, net of required reserves		825			825			194
Plum Point letter of credit capacity		101			101			—
Outstanding letters of credit		(1,061	)		(1,091	)		(157	)

Unused capacity		740			710			507
Cash—DHI		833	(2),(3)		280	(2)		243	(2)

Total available liquidity—DHI		1,573			990			750
Cash—Dynegy		37			43			128

Total available liquidity—Dynegy	$	1,610		$	1,033		$	878

(1)	In April and May 2007, we amended and restated the credit facility. Please see Note 8—Debt—Fifth Amended and Restated Credit Facility for further discussion.

(2)	The August 2, 2007, June 30, 2007 and December 31, 2006 amounts include approximately $75 million, $73 million and $46 million, respectively, of cash that remains in Europe and $14 million, $12 million and $10 million, respectively, of cash that remains in Canada.

(3)	The increase in DHI’s cash balance since June 30, 2007 was primarily due to proceeds received from the sale of our CoGen Lyondell facility.

Cash Flows from Operations. Dynegy had operating cash inflows of $157 million for the six months ended June 30, 2007. This consisted of $413 million in operating cash flows from our power generation business, offset by $9 million of cash outflows relating to our customer risk management business and $247 million of cash outflows relating to corporate-level expenses.

DHI had operating cash inflows of $171 million for the six months ended June 30, 2007. This consisted of $413 million in operating cash flows from our power generation business, offset by $9 million of cash outflows relating to our customer risk management business and $233 million of cash outflows relating to corporate-level expenses.

Please read “—Results of Operations—Operating Income” and “—Cash Flow Disclosures” for further discussion of factors impacting our operating cash flows for the periods presented.

Our future operating cash flows will vary based on a number of factors, many of which are beyond our control, including the price of natural gas and its correlation to power prices, the cost of coal and fuel oil, the value of ancillary services and capacity. Additionally, the availability of our plants during peak demand periods will be required to allow us to capture attractive market prices when available. Over the longer term, our operating cash flows also will be impacted by, among other things, our ability to tightly manage our operating costs, including maintenance costs in balance with ensuring that our plants are available to operate when markets offer attractive returns.

Cash on Hand. At August 2, 2007 and June 30, 2007, Dynegy had cash on hand of $870 million and $323 million, respectively, as compared to $371 million at the end of 2006. The decrease in cash on hand at June 30, 2007 as compared to the end of 2006 is primarily attributable to cash paid in connection with the Merger Agreement. The increase in cash on hand from June 30, 2007 to August 2, 2007 was primarily due to proceeds received from the sale of our CoGen Lyondell facility.

At August 2, 2007 and June 30, 2007, DHI had cash on hand of $833 million and $280 million, respectively, as compared to $243 million at the end of 2006. The increase in cash on hand at June 30, 2007 as compared to the end of 2006 is primarily attributable to cash provided by the operating activities of our generation business. The increase in cash on hand from June 30, 2007 to August 2, 2007 was primarily due to proceeds received from the sale of our CoGen Lyondell facility.

Revolver Capacity. On April 2, 2007, DHI entered into the Fifth Amended and Restated Credit Facility which replaced our former Fourth Amended and Restated Credit Facility. Please read Note 12—Debt beginning on page F-36 of Dynegy’s Form 10-K for further discussion of our former Fourth Amended and Restated Credit Facility. The Fifth Amended and Restated Credit Facility is our primary credit facility. On May 24, 2007, DHI entered into an amendment to the Fifth Amended and Restated Credit Facility. Please read Note 8—Debt—Fifth Amended and Restated Credit Facility for further discussion.

External Liquidity Sources

Our primary external liquidity sources are proceeds from asset sales and other types of capital-raising transactions, including potential debt and equity issuances.

Asset Sale Proceeds. On August 1, 2007, we completed our sale of our CoGen Lyondell power generation facility for approximately $470 million to EnergyCo., a joint venture between PNM Resources and a subsidiary of Cascade Investment, LLC. We expect to record an estimated $200 million gain related to the sale of the asset in the third quarter 2007. Please read Note 3—Discontinued Operations—GEN-WE Discontinued Operations—Cogen Lyondell for further discussion.

On January 31, 2007, we entered into an agreement to sell our interest in the Calcasieu power generation facility to Entergy for approximately $57 million, subject to regulatory approval. The transaction is expected to close in early 2008. Please read Note 3—Discontinued Operations—GEN-WE Discontinued Operations—Calcasieu for further discussion.

Consistent with industry practice, we regularly evaluate our generation fleet based primarily on geographic location, fuel supply, market structure and market recovery expectations. We consider divestitures of non-core generation assets where the balance of the above factors suggests that such assets’ earnings potential is limited or that the value that can be captured through a divestiture outweighs the benefits of continuing to own and operate such assets. In connection with this review, we are considering options to potentially sell our 576 MW Bluegrass generation facility and our 539 MW Heard County generation facility. Moreover, dispositions of one or more generation facilities could occur in 2007 or beyond. Were any such sale or disposition to be consummated, the disposition could result in accounting charges related to the affected asset(s), and our earnings and cash flows could be affected in 2007 and beyond.

Capital-Raising Transactions. As part of our ongoing efforts to maintain a capital structure that is closely aligned with the cash-generating potential of our asset-based business, which is subject to cyclical changes in commodity prices, we may explore additional sources of external liquidity. The timing of any transaction may be

impacted by events, such as strategic growth opportunities, development activities, legal judgments or regulatory requirements, which could require us to pursue additional capital in the near-term. The receptiveness of the capital markets to an offering of debt or equity securities cannot be assured and may be negatively impacted by, among other things, our non-investment grade credit ratings, significant debt maturities, long-term business prospects and other factors beyond our control. Any issuance of equity by Dynegy likely would have other effects as well, including stockholder dilution. Our ability to issue debt securities is limited by our financing agreements, including our Fifth Amended and Restated Credit Facility, as amended. Please read Note 8—Debt for further discussion.

In addition, we continually review and discuss opportunities to grow our company and to participate in what we believe will be continuing consolidation of the power generation industry. No definitive transaction has been agreed to and none can be guaranteed to occur; however, we have successfully executed on similar opportunities in the past and could do so again in the future. Depending on the terms and structure of any such transaction, we could issue significant debt and/or equity securities for capital-raising purposes. We also could be required to assume substantial debt securities and the underlying payment obligations.

Please read “Uncertainty of Forward-Looking Statements and Information” for additional factors that could impact our future operating results and financial condition.

RESULTS OF OPERATIONS—DYNEGY INC. and DYNEGY HOLDINGS INC.

Overview. In this section, we discuss our results of operations, both on a consolidated basis and, where appropriate, by segment, for the three- and six-month periods ended June 30, 2007 and 2006. At the end of this section, we have included our 2007 outlook for each segment.

We report results of our power generation business in the following segments: (i) GEN-MW, (ii) GEN-NE and (iii) GEN-WE. Following the completion of the Merger Agreement in April 2007, our previously named South segment has been renamed the GEN-WE segment and the power generation facilities located in California and Arizona acquired through the Merger Agreement are included in this segment. The Kendall, Ontelaunee and Plum Point power generation facilities acquired through the Merger Agreement are included in GEN-MW, and the Casco Bay and Bridgeport power generation facilities acquired through the Merger Agreement are included in GEN-NE. We also separately report results of our CRM business, which primarily consists of our remaining power tolling arrangement as well as the legacy physical gas supply contracts and gas transportation contracts and remaining legacy power and emission trading positions that remain from the third-party trading business that was substantially exited in 2002. Our unaudited condensed consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization. Because of the diversity among their respective operations, we report the results of each business as a separate segment in our unaudited condensed consolidated financial statements.

Three Months Ended June 30, 2007 and 2006

Summary Financial Information. The following tables provide summary financial data regarding Dynegy’s consolidated and segmented results of operations for the three-month periods ended June 30, 2007 and 2006, respectively:

Dynegy’s Results of Operations for the Three Months Ended June 30, 2007


	Power Generation
	GEN-MW			GEN-NE			GEN-WE			CRM			Other and Eliminations			Total
	(in millions)
Revenues	$	406		$	279		$	145		$	(2	)	$	—		$	828
Cost of sales, exclusive of depreciation and amortization expense shown separately below		(196	)		(213	)		(134	)		33			—			(510	)
Depreciation and amortization expense		(50	)		(12	)		(23	)		—			(3	)		(88	)
General and administrative expense		—			—			—			—			(48	)		(48	)

Operating income (loss)	$	160		$	54		$	(12	)	$	31		$	(51	)	$	182
Losses from unconsolidated investments		—			—			—			—			(2	)		(2	)
Other items, net		(9	)		—			—			(3	)		13			1
Interest expense																	(84	)

Income from continuing operations before income taxes																	97
Income tax expense																	(30	)

Income from continuing operations																	67
Income from discontinued operations, net of taxes																	9

Net income																$	76

Dynegy’s Results of Operations for the Three Months Ended June 30, 2006


	Power Generation
	GEN-MW			GEN-NE			GEN-WE			CRM			Other and Eliminations			Total
	(in millions)
Revenues	$	228		$	125		$	8		$	18		$	—		$	379
Cost of sales, exclusive of depreciation and amortization expense shown separately below		(114	)		(119	)		(5	)		(10	)		(1	)		(249	)
Depreciation and amortization expense		(43	)		(6	)		(3	)		—			(2	)		(54	)
Impairment and other charges		—			—			(9	)		—			—			(9	)
Gain on sale of assets, net		—			—			—			—			3			3
General and administrative expense		—			—			—			(16	)		(34	)		(50	)

Operating income (loss)	$	71		$	—		$	(9	)	$	(8	)	$	(34	)	$	20
Other items, net		—			2			1			(2	)		9			10
Interest expense																	(354	)

Loss from continuing operations before income taxes																	(324	)
Income tax benefit																	117

Loss from continuing operations																	(207	)
Income from discontinued operations, net of taxes																	—

Net loss																$	(207	)

The following tables provide summary financial data regarding DHI’s consolidated and segmented results of operations for the three-month periods ended June 30, 2007 and 2006, respectively:

DHI’s Results of Operations for the Three Months Ended June 30, 2007


	Power Generation
	GEN-MW			GEN-NE			GEN-WE			CRM			Other and Eliminations			Total
	(in millions)
Revenues	$	406		$	279		$	145		$	(2	)	$	—		$	828
Cost of sales, exclusive of depreciation and amortization expense shown separately below		(196	)		(213	)		(134	)		33			—			(510	)
Depreciation and amortization expense		(50	)		(12	)		(23	)		—			(3	)		(88	)
General and administrative expense		—			—			—			—			(46	)		(46	)

Operating income (loss)	$	160		$	54		$	(12	)	$	31		$	(49	)	$	184
Other items, net		(9	)		—			—			(3	)		15			3
Interest expense																	(84	)

Income from continuing operations before income taxes																	103
Income tax expense																	(21	)

Income from continuing operations																	82
Income from discontinued operations, net of taxes																	8

Net income																$	90

DHI’s Results of Operations for the Three Months Ended June 30, 2006


	Power Generation
	GEN-MW			GEN-NE			GEN-WE			CRM			Other and Eliminations			Total
	(in millions)
Revenues	$	228		$	125		$	8		$	18		$	—		$	379
Cost of sales, exclusive of depreciation and amortization expense shown separately below		(114	)		(119	)		(5	)		(10	)		(1	)		(249	)
Depreciation and amortization expense		(43	)		(6	)		(3	)		—			(2	)		(54	)
Impairment and other charges		—			—			(9	)		—			—			(9	)
Gain on sale of assets, net		—			—			—			—			3			3
General and administrative expense		—			—			—			(16	)		(33	)		(49	)

Operating income (loss)	$	71		$	—		$	(9	)	$	(8	)	$	(33	)	$	21
Other items, net		—			2			1			(2	)		9			10
Interest expense																	(305	)

Loss from continuing operations before income taxes																	(274	)
Income tax benefit																	94

Loss from continuing operations																	(180	)
Loss from discontinued operations, net of taxes																	(1	)

Net loss																$	(181	)

The following table provides summary segmented operating statistics for the three months ended June 30, 2007 and 2006, respectively:


	Three Months Ended June 30,
	2007		2006
GEN-MW
Million Megawatt Hours Generated (1)		6.0		4.9
Average Actual On-Peak Market Power Prices ($/MWh):
Cinergy (Cin Hub)	$	67	$	53
Commonwealth Edison (NI Hub)	$	62	$	53
PJM West	$	74	$	61

GEN-NE
Million Megawatt Hours Generated		1.8		0.9
Average Actual On-Peak Market Power Prices ($/MWh):
New York—Zone G	$	86	$	73
New York—Zone A	$	60	$	58
Mass Hub	$	77	$	67

GEN-WE
Million Megawatt Hours Generated (1)		3.5		0.9
Average Actual On-Peak Market Power Prices ($/MWh):
North Path 15 (NP-15)	$	69	$	53
Palo Verde	$	65	$	55

Average natural gas price—Henry Hub ($/MMBtu) (2)	$	7.54	$	6.53

(1)

Includes our ownership percentage in the MWh generated by our GEN-WE investment in Black Mountain for the three months ended June 30, 2007 and includes the MWh generated by our GEN-WE investments in West Coast Power and Black Mountain and our GEN-MW investment in Rocky Road for the three months ended June 30, 2006.

(2)	Calculated as the average of the daily gas prices for the period.

The following tables summarize significant items on a pre-tax basis affecting net income (loss) for the periods presented:


	Three Months Ended June 30, 2007
	Power Generation
	GEN-MW			GEN-NE		GEN-WE		CRM			Other & Eliminations			Total
	(in millions)
Discontinued operations	$	—		$	—	$	3	$	11		$	—		$	14
Illinois rate relief charge		(25	)		—		—		—			—			(25	)
Change in fair value of interest rate swaps, net of minority interest		(9	)		—		—		—			39			30
Settlement of Kendall toll		—			—		—		31			—			31

Total	$	(34	)	$	—	$	3	$	42		$	39		$	50


	Three Months Ended June 30, 2006
	Power Generation
	GEN-MW			GEN-NE		GEN-WE		CRM			Other & Eliminations			Total
	(in millions)
Debt conversion costs	$	—		$	—	$	—	$	—		$	(202	)	$	(202	)
Acceleration of financing costs		—			—		—		—			(33	)		(33	)
Legal and settlement charges		—			—		—		(16	)		—			(16	)

Total DHI		—			—		—		(16	)		(235	)		(251	)
Debt conversion costs		—			—		—		—			(45	)		(45	)
Legal and settlement charges		—			—		—		—			(2	)		(2	)

Total Dynegy	$	—		$	—	$	—	$	(16	)	$	(282	)	$	(298	)

Operating Income

Operating income for Dynegy was $182 million for the three months ended June 30, 2007, compared to $20 million for the three months ended June 30, 2006. Operating income for DHI was $184 million for the three months ended June 30, 2007, compared to $21 million for the three months ended June 30, 2006.

Power Generation—Midwest Segment. Operating income for GEN-MW was $160 million for the three months ended June 30, 2007, compared to $71 million for the three months ended June 30, 2006.

Results for the three months ended June 30, 2007 improved by $121 million as a result of higher volumes, increased market prices, improved pricing as a result of the Illinois reverse power procurement auction, the addition of the new Midwest plants acquired through the Merger and higher mark-to market gains offset partially by a $25 million charge related to Illinois rate relief.

Generated volumes increased by 22%, up from 4.9 million MWh for the second quarter 2006 to 6.0 million MWh for the same period in 2007. Average actual on-peak prices in NI Hub/ComEd pricing region increased from $53 per MWh in the second quarter 2006 to $62 per MWh for the second quarter 2007.

Beginning January 1, 2007, we began operating under two new energy product supply agreements with subsidiaries of Ameren Corporation through our participation in the Illinois reverse power procurement auction in 2006. Under these new agreements, we provide up to 1,400 MWh around the clock for prices of approximately $65 per megawatt-hour.

The Kendall and Ontelaunee plants acquired on April 2, 2007 provided results of $15 million for the three months ended June 30, 2007, exclusive of mark-to-market results discussed below.

GEN-MW’s results for the three months ended June 30, 2007 include mark-to-market gains of $45 million related to forward sales, compared to $1 million of mark-to-market gains for the three months ended June 30, 2006. The mark-to-market gains are primarily driven by power price decreases subsequent to March 31, 2007. Of the $45 million in 2007 mark-to-market gains, $16 million relates to positions that will settle in 2007, and the remaining $29 million relates to positions that will settle in 2008 and beyond. See Note 5—Risk Management Activities—Cash Flow Hedges for a discussion of our decision to no longer designate derivative transactions as cash flow hedges beginning with the second quarter 2007.

In July 2007, we entered into agreements with various parties to make payments of up to $25 million to support a comprehensive rate relief package for Illinois for electric consumers. These agreements are subject to the passage of certain related legislation, which currently awaits approval from the Illinois Governor. We recorded a second quarter 2007 pre-tax charge of $25 million, included as a cost of sales on our unaudited condensed consolidated statements of operations. Please see Note 10—Commitments and Contingencies—Illinois Auction Complaints for further discussion.

Depreciation expense increased from $43 million for the second quarter 2006 to $50 million for the second quarter 2007 primarily as a result of the new Midwest plants.

Power Generation—Northeast Segment. Operating income for GEN-NE was $54 million for the three months ended June 30, 2007, compared to zero for the three months ended June 30, 2006.

Results for the three months ended June 30, 2007 improved by $60 million as a result of increased market prices, the addition of the new Northeast plants acquired through the Merger and higher mark-to-market gains.

On peak market prices in New York Zone G and Zone A increased by 18% and 3%, respectively. Spark spreads widened due to these higher power prices.

Generated volumes increased by 100%, up from 0.9 million MWh for the second quarter 2006 to 1.8 million MWh for the same period in 2007. The volume increase was primarily driven by the new Northeast plants. The Bridgeport and Casco Bay plants provided total results of $7 million for the three months ended June 30, 2007, exclusive of mark-to-market results discussed below.

GEN-NE’s results for the three months ended June 30, 2007 include mark-to-market gains of $32 million related to forward sales, compared to no mark-to-market gains for the three months ended June 30, 2006. The mark-to-market gains are primarily driven by power price decreases subsequent to March 31, 2007. Of the $32 million in 2007 mark-to-market gains, $27 million relates to positions that will settle in 2007, and the remaining $5 million relates to positions that will settle in 2008 and beyond. See Note 5—Risk Management Activities—Cash Flow Hedges for a discussion of our decision to no longer designate derivative transactions as cash flow hedges beginning with the second quarter 2007.

Depreciation expense increased from $6 million for the second quarter 2006 to $12 million for the second quarter 2007 as a result of the new Northeast plants.

Power Generation—West Segment. Operating loss for GEN-WE was $12 million for three months ended June 30, 2007, compared to a loss of $9 million for the three months ended June 30, 2006. The 2006 results relate to our Heard County and Rockingham generation facilities. Results from our CoGen Lyondell and Calcasieu power generation facilities have been classified as discontinued operations for all periods presented.

Results for the three months ended June 30, 2007 improved by $8 million as a result of the addition of the new West plants acquired through the Merger partially offset by mark-to market losses.

Generated volumes were 3.5 MWh for the second quarter 2007, up from 0.9 million MWh for the second quarter 2006. The volume increase was primarily driven by the new West plants. The plants provided total results of $33 million for the three months ended June 30, 2007, exclusive of mark-to-market results discussed below.

GEN-WE’s results for the three months ended June 30, 2007 include mark-to-market losses of $25 million related to heat rate call-options and forward sales agreements, compared to zero mark-to-market losses for the three months ended June 30, 2006. The mark-to-market losses are primarily driven by unfavorable changes in the relative prices of natural gas and power subsequent to March 31, 2007. Of the $25 million mark-to-market losses in 2007, $4 million relates to positions that will settle in 2007, and the remaining $21 million relates to positions that will settle in 2008 and beyond. See Note 5—Risk Management Activities—Cash Flow Hedges for a discussion of our decision to no longer designate derivative transactions as cash flow hedges beginning with the second quarter 2007.

Depreciation expense increased from $3 million for the second quarter 2006 to $23 million for the second quarter 2007 primarily as a result of the new West plants. In addition, during the second quarter 2006, we recorded a $9 million impairment of our Rockingham facility, resulting from the announcement of our sale of the facility.

CRM. Operating income for the CRM segment was $31 million for the three months ended June 30, 2007, compared to operating loss of $8 million for the three months ended June 30, 2006. Our income in 2007 included a $31 million pre-tax gain associated with the acquisition of Kendall pursuant to EITF Issue No. 04-1. Prior to the acquisition, Kendall held a power tolling contract with our CRM segment. Upon completion of the Merger, this contract became an intercompany agreement, and was effectively eliminated on a consolidated basis, resulting in the $31 million gain. Please see Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions for further discussion.

Our 2006 loss was driven primarily by a $16 million increase in legal reserves resulting from additional activities during the period that negatively affected management’s assessment of the probable and estimable losses associated with the applicable proceedings. This was offset by the release of a disputed liability based on management’s estimate of the likely outcome as well as mark-to-market gains on our legacy emissions positions.

Other. Dynegy’s other operating loss for the three months ended June 30, 2007 was $51 million, compared with operating losses of $34 million for the three months ended June 30, 2006. Operating losses in both periods were comprised primarily of general and administrative expenses.

Dynegy’s consolidated general and administrative expenses were $48 million and $50 million for the three months ended June 30, 2007 and 2006, respectively. General and administrative expenses for the three months ended June 30, 2007 includes legal and settlement charges of $4 million, compared with legal and settlement charges of $18 million in the same period of 2006. Additionally, 2007 general and administrative expenses included a charge of approximately $6 million in connection with the accelerated vesting of restricted stock and stock option awards previously granted to employees, which vested in full upon closing of the Merger Agreement. The remaining increase from 2006 to 2007 is primarily a result of higher salaries and benefits due to the Merger.

DHI’s other operating loss for the three months ended June 30, 2007 was $49 million, compared with operating losses of $33 million for the three months ended June 30, 2006. Operating losses in both periods were comprised primarily of general and administrative expenses.

DHI’s consolidated general and administrative expenses were $46 million and $49 million for the three months ended June 30, 2007 and 2006, respectively. General and administrative expenses for the three months ended June 30, 2007 includes legal and settlement charges of $2 million, compared with legal and settlement charges of $16 million in the same period of 2006. Additionally, 2007 general and administrative expense included a charge of approximately $6 million in connection with the accelerated vesting of restricted stock and stock option awards previously granted to employees, which vested in full upon closing of the Merger Agreement. The remaining increase from 2006 to 2007 is primarily a result of higher salaries and benefits due to the Merger.

Earnings from Unconsolidated Investments

Dynegy’s losses from unconsolidated investments were $2 million for the three months ended June 30, 2007, compared with zero for the three months ended June 30, 2006. The losses for 2007 relate to Dynegy’s interest in DLS Power Holdings.

Other Items, Net

Dynegy’s other items, net, totaled $1 million of net income for the three months ended June 30, 2007, compared to $10 million of income for the three months ended June 30, 2006. The decrease is primarily associated with $9 million of minority interest expense recorded in 2007 related to the Plum Point development project. The expense is primarily due to the mark-to-market interest income recorded during the three months ended June 30, 2007 related to the interest rate swap agreements associated with the Plum Point Credit Agreement. Please see “Interest Expense” below for further discussion.

DHI’s other items, net, totaled $3 million of net income for the three months ended June 30, 2007, compared to $10 million of income for the three months ended June 30, 2006. The decrease is primarily associated with $9 million of minority interest expense recorded in 2007 related to the Plum Point development project. The expense is primarily due to the mark-to-market interest income recorded during the three months ended June 30, 2007 related to the interest rate swap agreements associated with the Plum Point Credit Agreement. Please see “Interest Expense” below for further discussion.

Interest Expense

Dynegy’s interest expense and debt conversion costs totaled $84 million for the three months ended June 30, 2007, compared to $354 million for the three months ended June 30, 2006. The decrease is primarily attributable to debt conversion costs and acceleration of financing costs resulting from our liability management program executed in the second quarter 2006. Included in interest expense for the three months ended June 30, 2007 is approximately $27 million of mark-to-market income from interest rate swap agreements associated with the Plum Point Term Facility. Effective July 1, 2007, these agreements have been designated as cash flow hedges. Also included in interest expense for the three months ended June 30, 2007 is approximately $12 million of income from interest rate swap agreements, prior to being terminated, that were associated with the portion of the debt repaid in late May 2007. The mark-to-market income included in interest expense for 2007 is offset by net losses of approximately $7 million in connection with the repayment of a portion of the project indebtedness assumed in connection with the Merger. These items were offset by higher interest expense incurred in 2007 due to higher 2007 debt balances resulting from the Merger Agreement.

DHI’s interest expense and debt conversion costs totaled $84 million for the three months ended June 30, 2007, compared to $305 million for the three months ended June 30, 2006. The decrease is primarily attributable to debt conversion costs and acceleration of financing costs resulting from our liability management program executed in the second quarter 2006. Included in interest expense for the three months ended June 30, 2007 is approximately $27 million of mark-to-market income from interest rate swap agreements associated with the Plum Point Term Facility. Effective July 1, 2007, these agreements have been designated as cash flow hedges. Also included in interest expense for the three months ended June 30, 2007 is approximately $12 million of income from interest rate swap agreements, prior to being terminated, that were associated with the portion of the debt repaid in late May 2007. The mark-to-market income included in interest expense for 2007 is offset by net losses of approximately $7 million in connection with the repayment of a portion of the project indebtedness assumed in connection with the Merger. These items were offset by higher interest expense incurred in 2007 due to higher 2007 debt balances resulting from the Merger Agreement.

Income Tax (Expense) Benefit

Dynegy reported an income tax expense from continuing operations of $30 million for the three months ended June 30, 2007, compared to an income tax benefit from continuing operations of $117 million for the three months ended June 30, 2006. The 2007 effective tax rate was 31%, compared to 36% in 2006.

DHI reported an income tax expense from continuing operations of $21 million for the three months ended June 30, 2007, compared to an income tax benefit from continuing operations of $94 million for the three months ended June 30, 2006. The 2007 effective tax rate was 20%, compared to 34% in 2006.

In general, differences between these effective rates and the statutory rate of 35% result primarily from the effect of state income taxes and adjustments to Dynegy’s reserve for uncertain tax positions.

As a result of the Merger Agreement, our effective state tax rate increased primarily as a result of the higher state tax rates in the states in which the LS assets are located. This increase was more than offset by the impact of decreases in the New York state income tax rate and the Texas margin tax credit rate during the three months ended June 30, 2007.

Discontinued Operations

Income From Discontinued Operations Before Taxes. Discontinued operations include Calcasieu and CoGen Lyondell power generation facilities in our GEN-WE segment, DMSLP in our former NGL segment and our U.K. CRM business in the CRM segment.

During the three months ended June 30, 2007, Dynegy’s pre-tax income from discontinued operations was $14 million ($9 million after-tax). Dynegy’s GEN-WE segment includes earnings of $3 million from the operation of the CoGen Lyondell and Calcasieu power generation facilities. Dynegy’s U.K. CRM business includes income of $11 million related to a favorable settlement of a legacy receivable.

During the three months ended June 30, 2006, Dynegy’s pre-tax loss from discontinued operations was $3 million (zero after-tax). Dynegy’s GEN-WE segment includes losses of $1 million from the operation of the CoGen Lyondell and Calcasieu generation facilities. Dynegy’s U.K. CRM business includes a loss of $2 million for the three months ended June 30, 2006, associated with the settlement of an outstanding contract.

During the three months ended June 30, 2007, DHI’s pre-tax income from discontinued operations was $14 million ($8 million after-tax). DHI’s GEN-WE segment includes earnings of $3 million from the operation of the CoGen Lyondell and Calcasieu power generation facilities. DHI’s U.K. CRM business includes income of $11 million related to a favorable settlement of a legacy receivable.

During the three months ended June 30, 2006, DHI’s pre-tax loss from discontinued operations was $3 million ($1 million after-tax). DHI’s GEN-WE segment includes losses of $1 million from the operation of the CoGen Lyondell and Calcasieu generation facilities. DHI’s U.K. CRM business includes a loss of $2 million for the three months ended June 30, 2006, associated with the settlement of an outstanding contract.

Income Tax (Expense) Benefit From Discontinued Operations.

Dynegy recorded an income tax expense from discontinued operations of $5 million during the three months ended June 30, 2007, compared to an income tax benefit from discontinued operations of $3 million during the three months ended June 30, 2006. The effective rates for the three months ended June 30, 2007 and 2006 were 36% and 100%, respectively. FIN No. 18, “Accounting for Income Taxes in Interim Periods an interpretation of APB Opinion No. 28” requires a detailed methodology of allocating income taxes between continuing and discontinued operations. This methodology often results in an effective rate for discontinued operations significantly different from the statutory rate of 35%.

DHI recorded an income tax expense from discontinued operations of $6 million during the three months ended June 30, 2007, compared to an income tax benefit from discontinued operations of $2 million during the three months ended June 30, 2006. The effective rates for the three months ended June 30, 2007 and 2006 were 42% and 67%, respectively. FIN No. 18, “Accounting for Income Taxes in Interim Periods an interpretation of APB Opinion No. 28” requires a detailed methodology of allocating income taxes between continuing and discontinued operations. This methodology often results in an effective rate for discontinued operations significantly different from the statutory rate of 35%.

Six Months Ended June 30, 2007 and 2006

Summary Financial Information. The following tables provide summary financial data regarding Dynegy’s consolidated and segmented results of operations for the six-month periods ended June 30, 2007 and 2006, respectively:

Dynegy’s Results of Operations for the Six Months Ended June 30, 2007


	Power Generation
	GEN-MW			GEN-NE			GEN-WE			CRM			Other and Eliminations			Total
	(in millions)
Revenues	$	678		$	503		$	145		$	7		$	—		$	1,333
Cost of sales, exclusive of depreciation and amortization expense shown separately below		(326	)		(389	)		(135	)		22			(1	)		(829	)
Depreciation and amortization expense		(92	)		(18	)		(24	)		—			(6	)		(140	)
General and administrative expense		—			—			—			—			(101	)		(101	)

Operating income (loss)	$	260		$	96		$	(14	)	$	29		$	(108	)	$	263
Losses from unconsolidated investments		—			—			—			—			(2	)		(2	)
Other items, net		(9	)		—			—			(3	)		21			9
Interest expense																	(151	)

Income from continuing operations before income taxes																	119
Income tax expense																	(36	)

Income from continuing operations																	83
Income from discontinued operations, net of taxes																	7

Net income																$	90

Dynegy’s Results of Operations for the Six Months Ended June 30, 2006


	Power Generation
	GEN-MW			GEN-NE			GEN-WE			CRM			Other and Eliminations			Total
	(in millions)
Revenues	$	484		$	317		$	59		$	59		$	—		$	919
Cost of sales, exclusive of depreciation and amortization expense shown separately below		(232	)		(279	)		(53	)		(22	)		(2	)		(588	)
Depreciation and amortization expense		(83	)		(12	)		(5	)		—			(10	)		(110	)
Impairment and other charges		—			—			(9	)		—			(2	)		(11	)
Gain on sale of assets, net		—			—			—			—			3			3
General and administrative expense		—			—			—			(31	)		(70	)		(101	)

Operating income (loss)	$	169		$	26		$	(8	)	$	6		$	(81	)	$	112
Earnings from unconsolidated investments		—			—			2			—			—			2
Other items, net		—			4			1			(1	)		26			30
Interest expense																	(452	)

Loss from continuing operations before income taxes																	(308	)
Income tax benefit																	109

Loss from continuing operations																	(199	)
Loss from discontinued operations, net of taxes																	(8	)
Cumulative effect of change in accounting principle, net of taxes																	1

Net loss																$	(206	)

The following tables provide summary financial data regarding DHI’s consolidated and segmented results of operations for the six-month periods ended June 30, 2007 and 2006, respectively:

DHI’s Results of Operations for the Six Months Ended June 30, 2007


	Power Generation
	GEN-MW			GEN-NE			GEN-WE			CRM			Other and Eliminations			Total
	(in millions)
Revenues	$	678		$	503		$	145		$	7		$	—		$	1,333
Cost of sales, exclusive of depreciation and amortization expense shown separately below		(326	)		(389	)		(135	)		22			(1	)		(829	)
Depreciation and amortization expense		(92	)		(18	)		(24	)		—			(6	)		(140	)
General and administrative expense		—			—			—			—			(82	)		(82	)

Operating income (loss)	$	260		$	96		$	(14	)	$	29		$	(89	)	$	282
Other items, net		(9	)		—			—			(3	)		19			7
Interest expense																	(151	)

Income from continuing operations before income taxes																	138
Income tax expense																	(32	)

Income from continuing operations																	106
Income from discontinued operations, net of taxes																	6

Net income																$	112

DHI’s Results of Operations for the Six Months Ended June 30, 2006


	Power Generation
	GEN-MW			GEN-NE			GEN-WE			CRM			Other and Eliminations			Total
	(in millions)
Revenues	$	484		$	317		$	59		$	59		$	—		$	919
Cost of sales, exclusive of depreciation and amortization expense shown separately below		(232	)		(279	)		(53	)		(22	)		(2	)		(588	)
Depreciation and amortization expense		(83	)		(12	)		(5	)		—			(10	)		(110	)
Impairment and other charges		—			—			(9	)		—			(2	)		(11	)
Gain on sale of assets, net		—			—			—			—			3			3
General and administrative expense		—			—			—			(31	)		(69	)		(100	)

Operating income (loss)	$	169		$	26		$	(8	)	$	6		$	(80	)	$	113
Earnings from unconsolidated investments		—			—			2			—			—			2
Other items, net		—			4			1			(1	)		23			27
Interest expense																	(400	)

Loss from continuing operations before income taxes																	(258	)
Income tax benefit																	89

Loss from continuing operations																	(169	)
Loss from discontinued operations, net of taxes																	(9	)

Net loss																$	(178	)

The following table provides summary segmented operating statistics for the six months ended June 30, 2007 and 2006, respectively:


	Six Months Ended June 30,
	2007		2006
GEN-MW
Million Megawatt Hours Generated (1)		11.6		10.3
Average Actual On-Peak Market Power Prices ($/MWh):
Cinergy (Cin Hub)	$	61	$	51
Commonwealth Edison (NI Hub)	$	58	$	52
PJM West	$	70	$	61

GEN-NE
Million Megawatt Hours Generated		3.8		1.9
Average Actual On-Peak Market Power Prices ($/MWh):
New York—Zone G	$	85	$	74
New York—Zone A	$	62	$	59
Mass Hub	$	79	$	71

GEN-WE
Million Megawatt Hours Generated (1)		4.3		2.0
Average Actual On-Peak Market Power Prices ($/MWh):
North Path 15 (NP-15)	$	65	$	55
Palo Verde	$	60	$	55

Average natural gas price—Henry Hub ($/MMBtu) (2)	$	7.35	$	7.14

(1)

Includes our ownership percentage in the MWh generated by our GEN-WE investment in Black Mountain for the six months ended June 30, 2007 and includes the MWh generated by our GEN-WE investments in West Coast Power and Black Mountain and our GEN-MW investment in Rocky Road for the six months ended June 30, 2006.

(2)	Calculated as the average of the daily gas prices for the period.

The following tables summarize significant items on a pre-tax basis affecting net income (loss) for the periods presented:


	Six Months Ended June 30, 2007
	Power Generation
	GEN-MW			GEN-NE		GEN-WE		CRM		Other			Total
	(in millions)
Discontinued operations	$	—		$	—	$	—	$	11	$	—		$	11
Legal and settlement charges		—			—		—		—		(2	)		(2	)
Illinois rate relief charge		(25	)		—		—		—		—			(25	)
Change in fair value of interest rate swaps, net of minority interest		(9	)		—		—		—		39			30
Settlement of Kendall toll		—			—		—		31		—			31

Total DHI		(34	)		—		—		42		37			45
Legal and settlement charges		—			—		—		—		(19	)		(19	)

Total Dynegy	$	(34	)	$	—	$	—	$	42	$	18		$	26


	Six Months Ended June 30, 2006
	Power Generation
	GEN-MW		GEN-NE		GEN-WE			CRM			Other			Total
	(in millions)
Debt conversion costs	$	—	$	—	$	—		$	—		$	(202	)	$	(202	)
Acceleration of financing costs		—		—		—			—			(34	)		(34	)
Legal and settlement charges		—		—		—			(31	)		—			(31	)
Discontinued operations		—		—		(15	)		(1	)		1			(15	)

Total DHI		—		—		(15	)		(32	)		(235	)		(282	)
Debt Conversion Costs		—		—		—			—			(45	)		(45	)
Legal and settlement charges		—		—		—			—			(2	)		(2	)

Total Dynegy	$	—	$	—	$	(15	)	$	(32	)	$	(282	)	$	(329	)

Operating Income

Operating income for Dynegy was $263 million for the six months ended June 30, 2007, compared to $112 million for the six months ended June 30, 2006. Operating income for DHI was $282 million for the six months ended June 30, 2007, compared to $113 million for the six months ended June 30, 2006.

Power Generation—Midwest Segment. Operating income for GEN-MW was $260 million for the six months ended June 30, 2007, compared to $169 million for the six months ended June 30, 2006.

Results for the six months ended June 30, 2007 improved by $100 million as a result of higher volumes, increased market prices, improved pricing as a result of the Illinois reverse power procurement auction, the addition of the new Midwest plants acquired through the Merger and higher mark-to-market gains partially by a $25 million charge related to Illinois rate relief.

Generated volumes increased by 13%, up from 10.3 million MWh for the six months ended June 30, 2006 to 11. 6 million MWh for the same period in 2007. Average actual on-peak prices in NI Hub/ComEd pricing region increased from $52 per MWh for the six months ended June 30, 2006 to $58 per MWh for the six months ended June 30, 2007.

The Kendall and Ontelaunee plants acquired on April 2, 2007 provided results of $15 million for the six months ended June 30, 2007, exclusive of mark-to-market results discussed below.

GEN-MW’s results for the six months ended June 30, 2007 include mark-to-market gains of $33 million related to forward sales, compared to $4 million mark-to-market gains for the six months ended June 30, 2006. The mark-to-market gains are primarily driven by power price decreases subsequent to December 31, 2006. Of the $33 million in 2007 of mark-to-market gains, $12 million relates to the positions which will settle in 2007, and the remaining $21 million relates to positions that will settle in 2008 and beyond. See Note 5—Risk Management Activities—Cash Flow Hedges for a discussion of our decision to no longer designate derivative transactions as cash flow hedges beginning with the second quarter 2007.

In July 2007, we entered into agreements with various parties to make payments of up to $25 million to support a comprehensive rate relief package for Illinois for electric consumers. These agreements are subject to the passage of certain related legislation, which currently awaits approval from the Illinois governor. We recorded a second quarter 2007 pre-tax charge of $25 million, included as a cost of sales on our unaudited condensed consolidated statements of operations. Please see Note 10—Commitments and Contingencies—Illinois Auction Complaints for further discussion.

Depreciation expense increased from $83 million for the six months ended June 30, 2006 to $92 million for the six months ended June 30, 2007 primarily as a result of as a result of the new Midwest plants and capital projects placed into service in 2006.

Power Generation—Northeast Segment. Operating income for GEN-NE was $96 million for the six months ended June 30, 2007, compared to $26 million for the six months ended June 30, 2006.

Results for the six months ended June 30, 2007 improved by $76 million as a result of increased market prices, the addition of the new Northeast plants acquired through the Merger and higher mark-to-market gains.

On peak market prices in New York Zone G and Zone A increased by 15% and 5%, respectively. Spark spreads widened due to higher power prices.

Generated volumes increased by 100%, up from 1.9 million MWh for the six months ended June 30, 2006 to 3.8 million MWh for the same period in 2007. The volume increase was partially driven by the new Northeast plants. The Bridgeport and Casco Bay plants provided total results of $7 million for the six months ended June 30, 2007, exclusive of mark-to-market results discussed below.

The volume increase was also a result of higher spark spreads and cooler weather in the first quarter 2007, which led to greater run times than in 2006. However, in the six months ended June 30, 2006, results were favorably impacted by $10 million due to an opportunistic sale of emissions credits that were not required for near-term operations of our facilities. This sale was not repeated in the six months ended June 30, 2007, as the facilities experienced greater run times.

GEN-NE’s results for the six months ended June 30, 2007 include mark-to-market gains of $30 million related to forward sales, compared to zero mark-to-market gains for the six months ended June 30, 2006. The mark-to-market gains are primarily driven by power price decreases subsequent to December 31, 2006. Of the $30 million in 2007 mark-to-market gains, $26 million relates to the positions which will settle in 2007, and the remaining $4 million relates to positions that will settle in 2008 and beyond. See Note 5—Risk Management Activities—Cash Flow Hedges for a discussion of our decision to no longer designate derivative transactions as cash flow hedges beginning with the second quarter 2007.

Depreciation expense increased from $12 million for the six months ended June 30, 2006 to $18 million for the six months ended June 30, 2007. This was primarily due to the new Northeast plants.

Power Generation—West Segment. Operating loss for GEN-WE was $14 million for the six months ended June 30, 2007, compared to a loss of $8 million for the six months ended June 30, 2006. The 2006 results relate to our Heard County and Rockingham generation facilities. Results from our CoGen Lyondell and Calcasieu power generation facilities have been classified as discontinued operations for all periods presented.

Results for the six months ended June 30, 2007 improved by $4 million as a result of the addition of the new West plants acquired through the Merger offset by mark-to-market losses described below.

Generated volumes were 4.3 million MWh for the six months ended June 30, 2007, up from 2.0 million MWh for the six months ended June 30, 2006. The volume increase was primarily driven by the new West plants. The plants provided total results of $33 million for the six months ended June 30, 2007, exclusive of mark-to-market results discussed below. The volume increase from the new West plants was partially offset by a reduction due to the sale of the Rockingham generation facility in late 2006.

GEN-WE’s results for the six months ended June 30, 2007 include mark-to-market losses of $27 million related to heat rate call-options and forward sales agreements, compared to zero mark-to-market losses for the six months ended June 30, 2006. The mark-to-market losses are primarily driven by unfavorable changes in the relative prices of gas and power subsequent to April 2, 2007. Of the $25 million in 2007 mark-to-market losses, $4 million relates to the positions which will settle in 2007, and the remaining $23 million relates to positions that will settle in 2008 and beyond. See Note 5—Risk Management Activities—Cash Flow Hedges for a discussion of our decision to no longer designate derivative transactions as cash flow hedges beginning with the second quarter 2007.

Depreciation expense increased from $5 million for the six months ended June 30, 2006 to $24 million for the six months ended June 30, 2007 primarily as a result of the new West plants. In addition, during the second quarter 2006, we recorded a $9 million impairment of our Rockingham facility, resulting from the announcement of our sale of the facility.

CRM. Operating income for the CRM segment was $29 million for the six months ended June 30, 2007, compared to $6 million for the six months ended June 30, 2006. Results for 2007 include a $31 million gain associated with the acquisition of Kendall pursuant to EITF Issue No. 04-1. Prior to the Merger, Kendall held a power tolling contract with our CRM segment. Upon completion of the Merger, this contract became an intercompany agreement, and was effectively eliminated on a consolidated basis, resulting in the $31 million gain. Please see Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions for further discussion.

Our 2006 income was driven primarily by mark-to-market gains on our legacy emissions positions and the release of a disputed liability based on management’s estimate of the likely outcome. This was offset by a $31 million increase in legal reserves resulting from additional activities during the period that negatively affected management’s assessment of the probable and estimable losses associated with the applicable proceedings.

Other. Dynegy’s other operating loss for the six months ended June 30, 2007 was $108 million, compared with operating losses of $81 million for the three months ended June 30, 2006. Operating losses in both periods were comprised primarily of general and administrative expenses.

Dynegy’s consolidated general and administrative expenses recorded in the six months ended June 30, 2007 and 2006 were $101 million in both periods. General and administrative expenses for the six months ended June 30, 2007 includes legal and settlement charges of $21 million, compared with legal and settlement charges of $33 million in the same period of 2006. Additionally, general and administrative expenses for 2007 included a charge of approximately $6 million in connection with the accelerated vesting of restricted stock and stock option awards previously granted to employees, which vested in full upon closing of the Merger Agreement. The remaining increase from 2006 to 2007 is primarily a result of higher salaries and benefits due to the Merger.

DHI’s other operating loss for the six months ended June 30, 2007 was $89 million, compared with operating losses of $80 million for the six months ended June 30, 2006. Operating losses in both periods were comprised primarily of general and administrative expense.

DHI’s consolidated general and administrative expenses recorded in the six months ended June 30, 2007 and 2006 were $82 million and $100 million, respectively. General and administrative expenses for the six months ended June 30, 2007 include legal and settlement charges of $2 million, compared with legal and settlement charges of $31 million in the same period of 2006. Additionally, general and administrative expenses in 2007 included a charge of approximately $6 million in connection with the accelerated vesting of restricted stock and stock option awards previously granted to employees, which vested in full upon closing of the Merger Agreement. The remaining increase from 2006 to 2007 is primarily a result of higher salaries and benefits due to the Merger.

Earnings from Unconsolidated Investments

Dynegy’s losses from unconsolidated investments were $2 million for the six months ended June 30, 2007, compared with earnings of $2 million for the six months ended June 30, 2006. Losses in 2007 relate to Dynegy’s interest in DLS Power Holdings. Earnings in 2006 relate to the GEN-WE investment in Black Mountain.

DHI’s earnings from unconsolidated investments were zero for the six months ended June 30, 2007, compared with earnings of $2 million the six months ended June 30, 2006. Earnings in 2006 relate to the GEN-WE investment in Black Mountain.

Other Items, Net

Dynegy’s other items, net totaled $9 million of income for the six months ended June 30, 2007, compared to $30 million of income for the six months ended June 30, 2006. The decrease is primarily associated with higher interest income in 2006 resulting from higher cash balances, as well as $9 million of minority interest expense recorded in 2007 related to the Plum Point development project. The expense is primarily due to the mark-to-market interest income recorded during the three months ended June 30, 2007 related to the interest rate swap agreements associated with the Plum Point Credit Agreement. Please see “Interest Expense” below for further discussion.

DHI’s other items, net totaled $7 million of income for the six months ended June 30, 2007, compared to $27 million of income for the six months ended June 30, 2006. The decrease is primarily associated with higher interest income in 2006 resulting from higher cash balances, as well as $9 million of minority interest expense recorded in 2007 related to the Plum Point development project. The expense is primarily due to the mark-to-market interest income recorded during the three months ended June 30, 2007 related to the interest rate swap agreements associated with the Plum Point Credit Agreement. Please see “Interest Expense” below for further discussion.

Interest Expense

Dynegy’s interest expense and debt conversion costs totaled $151 million for the six months ended June 30, 2007, compared to $452 million for the six months ended June 30, 2006. The decrease is primarily attributable to debt conversion costs and acceleration of financing costs resulting from our liability management program executed in the second quarter of 2006. Included in interest expense for the three months ended June 30, 2007 is approximately $27 million of mark-to-market income from interest rate swap agreements associated with the Plum Point Term Facility. Effective July 1, 2007, these agreements have been designated as cash flow hedges. Also included in interest expense for the three months ended June 30, 2007 is approximately $12 million of income from interest rate swap agreements, prior to being terminated, that were associated with the portion of the debt repaid in late May 2007. The mark-to-market income included in interest expense for 2007 is offset by net losses of approximately $7 million in connection with the repayment of a portion of the project indebtedness assumed in connection with the Merger. These items were offset by higher interest expense incurred in 2007 due to higher 2007 debt balances resulting from the Merger Agreement.

DHI’s interest expense and debt conversion costs totaled $151 million for the six months ended June 30, 2007, compared to $400 million for the six months ended June 30, 2006. The decrease is primarily attributable to debt conversion costs and acceleration of financing costs resulting from our liability management program executed in the second quarter of 2006. Included in interest expense for the three months ended June 30, 2007 is approximately $27 million of mark-to-market income from interest rate swap agreements associated with the Plum Point Term Facility. Effective July 1, 2007, these agreements have been designated as cash flow hedges. Also included in interest expense for the three months ended June 30, 2007 is approximately $12 million of income from interest rate swap agreements, prior to being terminated, that were associated with the portion of the debt repaid in late May 2007. The mark-to-market income included in interest expense for 2007 is offset by net losses of approximately $7 million in connection with the repayment of a portion of the project indebtedness assumed in connection with the Merger. These items were offset by higher interest expense incurred in 2007 due to higher 2007 debt balances resulting from the Merger Agreement.

Income Tax (Expense) Benefit

Dynegy reported an income tax expense from continuing operations of $36 million for the six months ended June 30, 2007, compared to an income tax benefit from continuing operations of $109 million for the six months ended June 30, 2006. The 2007 effective tax rate was 30%, compared to 35% in 2006. Dynegy’s overall effective tax rate in 2007 was different than the statutory rate of 35% due primarily to state income taxes and adjustments to Dynegy’s reserve for uncertain tax positions.

DHI reported an income tax expense from continuing operations of $32 million for the six months ended June 30, 2007, compared to an income tax benefit from continuing operations of $89 million for the six months ended June 30, 2006. The 2007 effective tax rate was 23%, compared to 34% in 2006. DHI’s overall effective tax rate in 2007 was different than the statutory rate of 35% due primarily to state income taxes and adjustments to Dynegy’s reserve for uncertain tax positions.

Discontinued Operations

Income From Discontinued Operations Before Taxes. Discontinued operations include Calcasieu and CoGen Lyondell in our GEN-WE segment, DMSLP in our former NGL segment and our U.K. CRM business in the CRM segment.

During the six months ended June 30, 2007, Dynegy’s pre-tax income from discontinued operations was $11 million ($7 million after-tax). Dynegy’s GEN-WE segment includes zero from the operation of the CoGen Lyondell and Calcasieu power generation facilities. Dynegy’s U.K. CRM business includes income of $11 million related to a favorable settlement of a legacy receivable.

During the six months ended June 30, 2006, Dynegy’s pre-tax loss from discontinued operations was $15 million ($8 million after-tax). Dynegy’s GEN-WE segment includes losses of $15 million from the operation of the CoGen Lyondell and Calcasieu power generation facilities. Dynegy’s U.K. CRM segment includes a loss of $1 million for the six months ended June 30, 2006, associated with the settlement of an outstanding contract. Dynegy also recorded pre-tax income of $1 million attributable to NGL.

During the six months ended June 30, 2007, DHI’s pre-tax income from discontinued operations was $11 million ($6 million after-tax). DHI’s GEN-WE segment includes zero from the operation of the CoGen Lyondell and Calcasieu power generation facilities. DHI’s U.K. CRM business includes income of $11 million related to a favorable settlement of a legacy receivable.

During the six months ended June 30, 2006, DHI’s pre-tax loss from discontinued operations was $15 million ($9 million after-tax). DHI’s GEN-WE segment includes losses of $15 million from the operation of the CoGen Lyondell and Calcasieu power generation facilities. DHI’s U.K. CRM segment includes a loss of $1 million for the six months ended June 30, 2006, associated with the settlement of an outstanding contract. DHI also recorded pre-tax income of $1 million attributable to NGL.

Income Tax (Expense) Benefit From Discontinued Operations.

Dynegy recorded an income tax expense from discontinued operations of $4 million during the six months ended June 30, 2007, compared to an income tax benefit from discontinued operations of $7 million during the six months ended June 30, 2006. The effective rates for the six months ended June 30, 2007 and 2006 are 36% and 46%, respectively. FIN No. 18, “Accounting for Income Taxes in Interim Periods an interpretation of APB Opinion No. 28” proscribes a detailed methodology of allocating income taxes between continuing and discontinued operations. This methodology often results in an effective rate for discontinued operations significantly different from the statutory rate of 35%.

DHI recorded an income tax expense from discontinued operations of $5 million during the six months ended June 30, 2007, compared to an income tax benefit from discontinued operations of $6 million during the six months ended June 30, 2006. The effective rates for the six months ended June 30, 2007 and 2006 are 45% and 40%, respectively. FIN No. 18, “Accounting for Income Taxes in Interim Periods an interpretation of APB Opinion No. 28” proscribes a detailed methodology of allocating income taxes between continuing and discontinued operations. This methodology often results in an effective rate for discontinued operations significantly different from the statutory rate of 35%.

Outlook

Our recently completed Merger Agreement with the LS Contributing Entities represents the transition from our previous era of self-restructuring and operations of our legacy fleet to a period of expanded, more diverse operations that provides greater scale and scope in our key markets and stronger positioning for future growth opportunities.

Generally, we expect that our future financial results will continue to reflect sensitivity to fuel and emissions commodity prices, market structure and prices for electric energy, ancillary services and capacity, transportation and transmission logistics, weather conditions and in-market asset availability (“IMA”). Our commercial team actively manages commodity price risk associated with our unsold power production by trading in the balance-of-year and the prompt year markets at physical hubs that are correlated with our assets. We also participate in various regional auctions and bilateral opportunities for capacity sales.

Compared to the legacy Dynegy assets, a higher percentage of our forecasted generation output from the assets acquired through the Merger Agreement is hedged through physical and financial agreements extending beyond the prompt year. Including volumes committed under contracts acquired with these assets, contracts resulting from the Illinois resource procurement auction and power and steam delivery commitments from our Independence facility, a substantial portion of the output from our fleet of power generation facilities is contracted for the balance of 2007. This includes RMR arrangements at our Morro Bay, South Bay and Oakland facilities. The remaining output from our facilities is available for other forward sales opportunities to capture attractive market prices when they are available. To the extent that we choose not to enter into forward sales, the gross margin from our assets is a function of price movements in the coal, natural gas, fuel oil and power commodity markets.

Our results will also continue to be impacted by environmental regulations and their impact on our financial condition and results of operations. In addition to CARB, various state and federal programs have been initiated or are being discussed. It is difficult to predict with certainty the precise outcome of these various initiatives and discussions or the resulting impact on our results of operations and financial condition. If some or all of the initiatives are adopted and implemented, Dynegy, DHI and similarly situated power generators could incur additional costs to develop, construct and operate power generation facilities, with the magnitude of any such cost increases to be influenced by, among other things:

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the structure and scope of final rules and regulations, including the level of emissions reductions required and the time period for these reductions;

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the ability to recover in the marketplace any associated increases in operating and/or capital costs;

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the demonstration of new technologies that make further emissions reductions a reality and any associated costs; and

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the risk of litigation and related adversary proceedings, particularly with respect to development projects and associated permitting activities.

Effective April 2, 2007, we issued termination notices to General Electric (“GE”) for LTSA contracts related to the Casco Bay, Arlington Valley and Moss Landing facilities. The parties have been addressing issues related to the termination of the LTSAs, and have entered into a Standstill and Tolling Agreement dated April 16, 2007 which tolls the effective date of the LTSA termination notices, and all related issues between the parties regarding the LTSAs. The parties are negotiating new arrangements during this standstill period which would resolve all issues between the parties related to the LTSAs. If no new arrangements are agreed to, we will seek other parties to provide the services currently covered by the LTSAs and will actively address any other issues that arise in connection with the terminations.

The following summarizes our outlook for our power generation business by reportable segment.

GEN-MW. We expect our results to continue to be impacted by power prices, fuel prices, fuel availability and IMA.

For the remainder of 2007, GEN-MW results will continue to be affected by the delivery obligations resulting from our participation in the Illinois resource procurement auction. The power commodity price under the auction-related agreements is higher than existed under our previous contract. The price we will receive under the auction contract in 2007 is approximately $65/MWh. Under the auction contract, we assume increased costs and penalty risks associated with managing delivered power volumes. The price we received under the previous contract averaged approximately $42/MWh in 2006, and was a function of the amount of power called on by IP under the previous contract. We anticipate that the revenues generated by our Midwest facilities will continue to benefit in 2007 from the implementation of contracts resulting from the auction and the sale of additional volumes into the MISO wholesale markets at prevailing market prices.

Another factor impacting our results in the Midwest in 2007 will be the regulatory environment in Illinois. Recent legislation is expected to provide more certainty with respect to the Illinois regulatory environment, at least for the near term. Please read “Recent Developments” and Note 10—Commitments and Contingencies—Illinois Auction Complaints for further discussion.

In 2005, DMG entered into a comprehensive, Midwest system-wide settlement with the EPA and other parties, resolving the environmental litigation related to our Baldwin Energy Complex in Illinois. The settlement will require substantial emission reductions from our Illinois coal-fired power plants and the completion of several supplemental environmental projects in the Midwest. Through June 30, 2007, DMG had achieved all emission reductions scheduled to date under the Consent Decree and was developing plans to install additional emission control equipment to meet future Consent Decree emission limits. DMG has constructed a mercury control project at the Vermilion Power Station that began operation in June 2007. Our estimated costs associated with the Consent Decree projects, which we expect to incur through 2012, are approximately $775 million. We expect to have spent $135 million of this amount by December 31, 2007. Expected spending associated with the Consent Decree for the next four years and thereafter are as follows: 2008—$150 million, 2009–$180 million, 2010—$170 million, 2011—$100 million and thereafter—$40 million.

Through 2010, 97% of our Midwest coal requirements are contracted. Additionally, 98% of our coal requirements for 2007 and 2008 are contracted at a fixed price. Our longer term results are sensitive to changes in coal prices to the extent that our current fixed prices are adjusted through contract re-openers or related provisions.

Our results will continue to be affected by IMA. We use IMA to monitor fleet performance over time. This measure quantifies the percentage of generation for each of our 14 major steam units that were available when market prices were favorable for participation. Through our focus on safe and efficient operations, we seek to maximize our IMA and, as a result, our revenue generating opportunities. The IMA for our coal-fired fleet for the six months ended June 30, 2007 was approximately 92%, compared to 88% for the comparable period of 2006. (In 2007, we modified the way we calculate IMA to better reflect the capabilities of the units due to seasonal variations. These changes had minimal effects on the year over year comparison in the second quarter, but could have more pronounced effects as the summer season progresses.) We attempt to schedule maintenance and repair work to minimize downtime during peak demand periods, to the extent doing so does not compromise a safe working environment for our employees and contractors.

In connection with the Merger discussed in Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions, we acquired assets in Illinois and Pennsylvania. These assets include the 1,200 MW Kendall natural gas-fired facility in Minooka, IL and the 580 MW Ontelaunee natural gas-fired facility in Ontelaunee Township, PA. With respect to the Kendall facility, 275 MW of the facility’s capacity is committed to a subsidiary of Constellation Energy (“Constellation”) under a power purchase agreement that extends through 2017. An additional 550 MW of capacity is committed under another agreement with Constellation, which extends through November 2008. These power purchase agreements provide us with predictable contracted revenues, and mitigate the effects of fluctuating market prices for electricity.

The Ontelaunee facility sells its energy, capacity and other ancillary services to wholesale electricity customers directly on the spot market. However, exposure to the market prices of energy has been hedged under a financially settled heat rate call-option agreement.

Our 576 MW Bluegrass generation facility is being considered for a potential sale. Please read “Asset Sale Proceeds” for further discussion.

GEN-NE. We expect our results to continue to be impacted by power prices, fuel prices, fuel availability and IMA. Spreads between power and fuel costs are expected to remain volatile as both fuel and power prices change based on demand and weather. This volatility has significant impact on the run-time for the Roseton unit. All of our coal supply requirements for 2007 are contracted at a fixed price. We continue to maintain sufficient coal and oil inventories and contractual commitments intended to provide us with a stable fuel supply.

Additionally, our results could be affected by potential changes in New York, Maine and/or Connecticut state environmental regulations, as well as our ability to obtain permits necessary for the operation of our facilities. Please see Note 10—Commitments and Contingencies—Danskammer State Pollutant Discharge Elimination System Permit and Note 10—Commitments and Contingencies—Roseton State Pollutant Discharge Elimination System Permit, respectively, for further discussion.

In connection with the Merger discussed in Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions, we acquired assets in Connecticut and Maine. These assets include the 527 MW Bridgeport natural gas-fired facility in Bridgeport, CT and the 540 MW Casco Bay natural gas-fired facility in Veazie, ME.

The Bridgeport facility had been operating pursuant to the terms of the Bridgeport RMR agreement, subject to the outcome of ongoing proceedings before the FERC to resolve the question of whether Bridgeport is eligible for an RMR agreement. On May 25, 2007, Bridgeport and the intervening parties submitted a Joint Offer of Settlement, which effectively terminated the RMR Agreement as of May 31, 2007. In addition, the Settlement stipulated that within 30 days of FERC approval Bridgeport will refund ISO-NE $12.5 million and any RMR revenues received by Bridgeport from the ISO-NE under the amended RMR agreement for the calendar months April 2007 and May 2007. Under the Settlement, Bridgeport will no longer be required to submit stipulated bids as of June 1, 2007 therein allowing Bridgeport to more fully participate as a merchant generator in the ISO-NE market. The Settlement was certified as an uncontested settlement on June 29, 2007 by the Presiding Administrative Law Judge and was accepted by FERC on August 3, 2007.

GEN-WE. In connection with the Merger discussed in Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions, we acquired a portfolio of assets in California and Arizona. These assets include six facilities located in California (Moss Landing, Morro Bay, South Bay and Oakland) and Arizona (Arlington Valley and Griffith), with a total capacity of 5,545 MW. Moss Landing, Morro Bay, and Griffith are subject to certain power purchase agreements under which the buyer pays the power generation facility a fixed monthly payment for the right to call energy, capacity and ancillary services from the power generation facility. The South Bay and Oakland facilities operate under RMR agreements with the CAISO.

Moss Landing, Arlington Valley and Griffith sell energy, capacity and/or other ancillary services to wholesale electricity customers directly in the spot market. Several financially-settled heat rate call-options are in effect that mitigate the exposure of these facilities to changes in the market price of energy.

Our GEN-WE segment will no longer benefit from the earnings from the CoGen Lyondell facility due to the completion of the sale of this facility on August 1, 2007. For the six months ended June 30, 2007, we recorded operating income of $5 million related to the operation of CoGen Lyondell. This amount has been reclassified as income from discontinued operations. Additionally, our 539 MW Heard County generation facility is being considered for a potential sale. Please read “Asset Sale Proceeds” for further discussion.

DLS Power Development. Through Dynegy’s interest in DLS Power Development, Dynegy and LS Associates continue to move forward with the Sandy Creek Project, developing a 900 MW scrubbed, pulverized coal generation facility in Texas. The validity of the project’s air permit was recently upheld in district court, allowing the project to proceed with plans to sell undivided ownership interests in the project, and to arrange for construction financing. Management expects that Dynegy will make an equity commitment to the project during the third quarter of 2007.

DLS Power Development also continues to move forward with the Long Leaf Project, which comprises development of a 600 MW scrubbed pulverized coal generating facility located in Georgia. During the second quarter of 2007, this project received all necessary permits, although certain challengers are contesting the validity of these permits. Management believes the validity of the permits will be upheld, and could seek construction financing and power purchase agreements for future generation from the facility by first or second quarter of 2008. The DLS Power Development portfolio is anticipated to be dynamic in nature, with changes in projects and priorities likely to occur based on the joint venture parties’ views of market prices, supply/demand balances, contract availability and the terms thereof, environmental implications and other factors that they deem relevant.

Cash Flow Disclosures

The following table includes data from the operating section of our unaudited condensed consolidated statements of cash flows and includes cash flows from our discontinued operations, which are disclosed on a net basis in loss from discontinued operations, net of tax, in our unaudited condensed consolidated statements of operations:


	Dynegy Inc.						Dynegy Holdings Inc.
	Six Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
	(in millions)
Operating cash flows from our generation businesses	$	413		$	271		$	413		$	272
Operating cash flows from our customer risk management business		(9	)		(392	)		(9	)		(392	)
Other operating cash flows		(247	)		(247	)		(233	)		(258	)

Net cash provided by (used) in operating activities	$	157		$	(368	)	$	171		$	(378	)

Operating Cash Flow

Dynegy. Dynegy’s cash flow provided by operations totaled $157 million for the six months ended June 30, 2007. During the six months ended June 30, 2007, our power generation business provided positive cash flow from operations of $413 million primarily due to positive earnings for the period. Our customer risk management business used approximately $9 million in cash partially offset by the receipt of approximately $32 million from the sale of a legacy receivable. Other and Eliminations includes a use of approximately $247 million in cash primarily due to interest payments to service debt and general and administrative expenses and a $17 million legal settlement payment associated with the Illinova Arbitration.

Dynegy’s cash flow used in operations totaled $368 million for the six months ended June 30, 2006. GEN provided cash flow from operations of $271 million, primarily due to positive earnings for the period. Our CRM segment used cash flow of approximately $392 million primarily due to a $370 million termination payment on our Sterlington tolling contract. Other and Eliminations includes a use of approximately $247 million in cash primarily due to interest payments to service debt and general and administrative expenses, partially offset by interest income on cash balances and the receipt of approximately $20 million associated with the resolution of a legal dispute.

DHI. DHI’s cash flow provided by operations totaled $171 million for the six months ended June 30, 2007. During the six months ended June 30, 2007, our power generation business provided positive cash flow from operations of $413 million primarily due to positive earnings for the period. Our customer risk management business used approximately $9 million in cash partially offset by the receipt of approximately $32 million from the sale of a legacy receivable. Other and Eliminations includes a use of approximately $233 million in cash primarily due to interest payments to service debt and general and administrative expense.

DHI’s cash flow used in operations totaled $378 million for the six months ended June 30, 2006. GEN provided cash flow from operations of $272 million, primarily due to positive earnings for the period. Our CRM segment used cash flow of approximately $392 million primarily due to a $370 million termination payment on our Sterlington tolling contract. Other and Eliminations includes a use of approximately $258 million in cash primarily due to interest payments to service debt and general and administrative expenses, partially offset by interest income on cash balances.

Capital Expenditures and Investing Activities

Dynegy. Dynegy’s cash used in investing activities during the six months ended June 30, 2007 totaled $873 million. Capital spending of $153 million was primarily comprised of $115 million, $19 million, and $11 million for our GEN-MW, GEN-NE, and GEN-WE segments, respectively. Capital spending for the GEN-MW segment

includes $54 million associated with the construction of the Plum Point facility. The remaining capital spending for the GEN-MW and GEN-WE segments primarily related to maintenance and environmental projects, while spending in Dynegy’s GEN-NE segment primarily related to maintenance. Additionally, Dynegy made $5 million in contributions to DLS Power Holdings during the six months ended June 30, 2007.

Cash used in connection with the completion of the Merger Agreement, net of cash acquired, was $126 million. Please see Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions for further discussion. The increase in restricted cash of $589 million related primarily to a $650 million deposit associated with our cash collateralized facility, partially offset by the release of Independence restricted cash due to the posting of a letter of credit.

Dynegy’s cash provided by investing activities during the six months ended June 30, 2006 totaled $271 million. Capital spending of $59 million was primarily comprised of $36 million, $7 million, and $12 million in the GEN-MW, GEN-NE, and GEN-WE segments, respectively. The capital spending for the GEN-MW segment primarily related to maintenance and environmental capital projects, as well as $1 million in development capital associated with the completion of the Vermilion PRB conversion. Capital spending in our GEN-NE and GEN-WE segments primarily related to maintenance and environmental projects.

Net proceeds from the sale and acquisition of unconsolidated investments, net of cash acquired totaled $165 million in the 2006 period. This included net cash proceeds of $205 million from the sale of our 50% ownership interest in West Coast Power to NRG. This was partially offset by $40 million, net of cash acquired, associated with our acquisition of NRG’s 50% ownership interest in Rocky Road.

The decrease in restricted cash of $162 million related primarily to the return of our $335 million deposit associated with our former cash collateralized facility and a $27 million decrease in the Independence restricted cash balance, offset by a $200 million deposit associated with our cash collateralized facility.

DHI. DHI’s cash used in investing activities during the six months ended June 30, 2007 totaled $737 million. Capital spending of $153 million was primarily comprised of $115 million, $19 million, and $11 million for our GEN-MW, GEN-NE, and GEN-WE segments, respectively. Capital spending for the GEN-MW segment includes $54 million associated with the construction of the Plum Point facility. The remaining capital spending for the GEN-MW and GEN-WE segments primarily related to maintenance and environmental projects, while spending in Dynegy’s GEN-NE segment primarily related to maintenance.

The decrease in restricted cash of $589 million related primarily to a $650 million deposit associated with our cash collateralized facility, partially offset by the release of Independence restricted cash due to the posting of a letter of credit.

DHI’s cash provided by investing activities during the six months ended June 30, 2006 totaled $272 million. Capital spending of $59 million was primarily comprised of $36 million, $7 million, and $12 million in the GEN-MW, GEN-NE, and GEN-WE segments, respectively. The capital spending for the GEN-MW segment primarily related to maintenance and environmental capital projects, as well as $1 million in development capital associated with the completion of the Vermilion PRB conversion. Capital spending in our GEN-NE and GEN-WE segments primarily related to maintenance and environmental projects.

Net proceeds from the sale and acquisition of unconsolidated investments, net of cash acquired totaled $165 million. This included net cash proceeds of $205 million from the sale of our 50% ownership interest in West Coast Power to NRG. This was partially offset by $40 million, net of cash acquired, associated with our acquisition of NRG’s 50% ownership interest in Rocky Road.

Financing Activities

Dynegy. Dynegy’s cash provided by financing activities during the six months ended June 30, 2007 totaled $668 million. During the six months ended June 30, 2007, Dynegy received proceeds from long-term borrowings from the following sources, net of approximately $31 million of debt issuance costs:

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$1,650 million in aggregate principal amount from our Senior Unsecured Notes due 2015 and 2019;

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$665 million in aggregate principal amount on our letter of credit facilities;

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$275 million in aggregate principal amount on our revolver due 2012;

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$70 million senior secured term loan facility due 2013; and

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$34 million in aggregate principal amount on our Plum Point Construction Loan.

These borrowings were partially offset by $1,994 million of payments:

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$396 million in aggregate principal amount on our Kendall Senior Secured Term Loan Facility;

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$150 million in aggregate principal amount on our Ontelaunee term loan due 2009;

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$919 million in aggregate principal amount on our Gen Finance Term Loan;

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$150 million in aggregate principal amount on our Gen Finance Term Loan;

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$275 million promissory note to LS;

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$70 million Griffith debt;

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$19 million in aggregate principal amount on our 8.50% secured bonds due 2007; and

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$15 million in aggregate principal amount on our letter of credit facilities.

Dynegy’s cash used in financing activities during the six months ended June 30, 2006 totaled $1,094 million. Repayments of long-term debt totaled $1,683 million for the six months ended June 30, 2006 and consisted of the following payments:

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$900 million in aggregate principal amount on our Second Priority Senior Secured Notes due 2013;

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$614 million in aggregate principal amount on our Second Priority Senior Secured Notes due 2010;

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$151 million in aggregate principal amount on our Second Priority Senior Secured Notes due 2008; and

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$18 million in aggregate principal amount on our 8.50% secured bonds due 2007.

In addition to the above repayments, we redeemed all of the outstanding shares of our Series C Preferred for $400 million.

Debt conversion costs of $247 million consisted of the following payments:

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$202 million to redeem the Second Priority Senior Secured Notes mentioned above, including approximately $3 million of transaction costs;

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$44 million aggregate premium to induce conversion of our $225 million 4.75% Convertible Subordinated Debentures due 2023; and

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$1 million in transaction costs associated with the redemption of our Series C Preferred.

The repayments were partially offset by $1,071 million of proceeds from the following sources, net of approximately $29 million of debt issuance costs:

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$750 million aggregate principal amount from our Senior Unsecured Notes due 2016;

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$200 million, LIBOR + 1.75% letter of credit facility due 2012; and

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$150 million, LIBOR + 1.75% term loan due 2012.

Proceeds from the issuance of common stock consisted primarily of approximately $178 million in proceeds from a common stock offering of 40.25 million shares of Dynegy’s Class A common stock at $4.60 per share, net of underwriting fees. Dividend payments totaling $17 million were also made on Dynegy’s Series C Preferred prior to its redemption.

DHI. DHI’s cash provided by financing activities during the six months ended June 30, 2007 totaled $603 million. During the six months ended June 30, 2007, DHI received proceeds from long-term borrowings from the following sources, net of approximately $31 million of debt issuance costs:

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$1,650 million in aggregate principal amount from our Senior Unsecured Notes due 2015 and 2019;

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$665 million in aggregate principal amount on our letter of credit facilities;

•

$275 million in aggregate principal amount on our revolver due 2012;

•

$70 million in aggregate principal amount on our senior secured term loan facility due 2013; and

•

$34 million in aggregate principal amount on our Plum Point Credit Agreement Facility.

These borrowings were partially offset by $1,719 million of payments:

•

$396 million in aggregate principal amount on our Kendall Senior Secured Term Loan Facility;

•

$150 million in aggregate principal amount on our Ontelaunee term loan due 2009;

•

$919 million in aggregate principal amount on our Gen Finance Term Loan;

•

$150 million in aggregate principal amount on our Gen Finance Term Loan;

•

$70 million Griffith debt;

•

$19 million in aggregate principal amount on our 8.50% secured bonds due 2007; and

•

$15 million in aggregate principal amount on our letter of credit facilities.

Cash used in financing activities for the six months ended June 30, 2007 also includes dividend payments to Dynegy totalling $342 million.

DHI’s cash used in financing activities during the six months ended June 30, 2006 totaled $985 million. Repayments of long-term debt totaled $1,683 million for the six months ended June 30, 2006 and consisted of the following payments:

•

$900 million in aggregate principal amount on our Second Priority Senior Secured Notes due 2013;

•

$614 million in aggregate principal amount on our Second Priority Senior Secured Notes due 2010;

•

$151 million in aggregate principal amount on our Second Priority Senior Secured Notes due 2008; and

•

$18 million in aggregate principal amount on our 8.50% secured bonds due 2007.

Debt conversion costs of $202 million consisted of payments to redeem the Second Priority Senior Secured Notes mentioned above, including approximately $3 million of transaction costs;

The repayments were partially offset by $1,071 million of proceeds from the following sources, net of approximately $29 million of debt issuance costs:

•

$750 million aggregate principal amount from our Senior Unsecured Notes due 2016;

•

$200 million, LIBOR + 1.75% letter of credit facility due 2012; and

•

$150 million, LIBOR + 1.75% term loan due 2012.

Cash used in financing activities for the six months ended June 30, 2006 also includes $170 million in payments to Dynegy, which consists of repayments of borrowings of $120 million and a dividend payment of $50 million.

RISK-MANAGEMENT DISCLOSURES

The following table provides a reconciliation of the risk-management data on the unaudited condensed consolidated balance sheets:


	As of and for the Six Months Ended June 30, 2007
	(in millions)
Balance Sheet Risk-Management Accounts
Fair value of portfolio at January 1, 2007	$	53
Risk-management gains recognized through the income statement in the period, net		75
Cash received related to risk-management contracts settled in the period, net		(17	)
Changes in fair value as a result of a change in valuation technique (1)		—
Non-cash adjustments and other (2)		(136	)

Fair value of portfolio at June 30, 2007	$	(25	)

(1)	Our modeling methodology has been consistently applied.

(2)	This amount consists of $38 million in net risk management liabilities acquired in connection with the Merger Agreement as well as changes in value associated with cash flow hedges on forward power sales and fair value hedges on debt.

The net risk management liability of $25 million is the aggregate of the following line items on our condensed consolidated balance sheets: Current Assets—Assets from risk-management activities, Other Assets—Assets from risk-management activities, Current Liabilities—Liabilities from risk-management activities and Other Liabilities—Liabilities from risk-management activities.

Risk-Management Asset and Liability Disclosures. The following tables depict the mark-to-market value and cash flow components of our net risk-management assets and liabilities at June 30, 2007 and December 31, 2006. As opportunities arise to monetize positions that we believe will result in an economic benefit to us, we may receive or pay cash in periods other than those depicted below:

Mark-to-Market Value of Net Risk-Management Assets (1)


	Total			2007 (2)			2008			2009			2010			2011		Thereafter
	(in millions)
June 30, 2007	$	(1	)	$	74		$	(13	)	$	(33	)	$	(36	)	$	2	$	5
December 31, 2006		(44	)		(45	)		(3	)		—			—			1		3

Increase (decrease) (3)	$	43		$	119		$	(10	)	$	(33	)	$	(36	)	$	1	$	2

(1)

The table reflects the fair value of our risk-management asset position, which considers time value, credit, price and other reserves necessary to determine fair value. These amounts exclude the fair value associated with certain derivative instruments designated as hedges. The net risk-management liabilities at June 30, 2007 of $25 million on the unaudited condensed consolidated balance sheets include the $1 million herein as well as hedging instruments. Cash flows have been segregated between periods based on the delivery date required in the individual contracts.

(2)	Amounts represent July 1 to December 31, 2007 values in the June 30, 2007 row and January 1 to December 31, 2007 values in the December 31, 2006 row.

(3)

Increase since December 31, 2007 primarily due to the settlement of a large portion of risk-management liabilities in the first half of 2007 and mark-to-market gains recognized in the second quarter of 2007, partially offset by $39 million in net risk-management liabilities acquired in connection with the Merger Agreement.

Cash Flow Components of Net Risk-Management Asset


	Six Months Ended June 30, 2007		Six Months Ended December 31, 2007		Total 2007			2008			2009			2010			2011		Thereafter
	(in millions)
June 30, 2007 (1)	$	34	$	14	$	48		$	42		$	(12	)	$	(14	)	$	2	$	6
December 31, 2006						(45	)		(4	)		—			—			1		5

Increase (decrease)					$	93		$	46		$	(12	)	$	(14	)	$	1	$	1

(1)

The cash flow values for 2007 reflect realized cash flows for the six months ended June 30, 2007 and anticipated undiscounted cash inflows and outflows by contract based on the tenor of individual contract position for the remaining periods. These anticipated undiscounted cash flows have not been adjusted for counterparty credit or other reserves. These amounts exclude the cash flows associated with certain derivative instruments designated as hedges.

The following table provides an assessment of net contract values by year as of June 30, 2007, based on our valuation methodology:

Net Fair Value of Risk-Management Portfolio


	Total			2007			2008			2009			2010			2011		Thereafter
	(in millions)
Market Quotations (1)	$	54		$	88		$	2		$	(18	)	$	(25	)	$	2	$	5
Prices Based on Models		(55	)		(14	)		(15	)		(15	)		(11	)		—		—

Total	$	(1	)	$	74		$	(13	)	$	(33	)	$	(36	)	$	2	$	5

(1)	Prices obtained from actively traded, liquid markets for commodities other than natural gas positions. All natural gas positions for all periods are contained in this line based on available market quotations.

UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION

This Form 10-Q includes statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as “forward-looking statements” by both Dynegy and DHI. All statements included or incorporated by reference in this quarterly report, other than statements of historical fact, that address activities, events or developments that we or our management expect, believe or anticipate will or may occur in the future are forward-looking statements. These statements represent our reasonable judgment on the future based on various factors and using numerous assumptions and are subject to known and unknown risks, uncertainties and other factors that could cause our actual results and financial position to differ materially from those contemplated by the statements. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as “anticipate,” “estimate”, “project”, “forecast”, “plan”, “may”, “will”, “should”, “expect” and other words of similar meaning. In particular, these include, but are not limited to, statements relating to the following:

•

anticipated benefits of diversifying our operations, including the merger with the LS Contributing Entities;

•

beliefs and expectations regarding any and all joint venture projects with the LS Contributing Entities;

•

projected operating or financial results, including anticipated cash flows from operations, revenues and profitability;

•

expectations regarding capital expenditures, interest expense and other payments;

•

beliefs and assumptions about economic conditions and the demand for electricity;

•

beliefs about commodity pricing and generation volumes;

•

our focus on safety and our ability to efficiently operate our assets so as to maximize our revenue generating opportunities;

•

strategies to capture opportunities presented by rising commodity prices and strategies to manage our exposure to energy price volatility;

•

beliefs and assumptions relating to liquidity;

•

statements related to the effects of changing to mark-to-market accounting including any related to gains and losses in earnings or value changes related to market price volatility;

•

strategies to address our substantial leverage, or to access the capital markets;

•

measures to compete effectively with industry participants;

•

beliefs and assumptions about market competition, fuel supply, generation capacity and regional supply and demand characteristics of the wholesale power generation market;

•

sufficiency of coal, fuel oil and natural gas inventories and transportation, including strategies to deploy coal supplies;

•

beliefs about the outcome of legal, regulatory and administrative matters;

•

expectations regarding environmental matters, including costs of compliance, availability and adequacy of emission credits, and the impact of ongoing proceedings and potential regulations, including those relating to global warming;

•

the disposition and resolution of settlements, complaints, and suits related to the Illinois Power Auction and impacts that these may have;

•

expectations and estimates regarding the DMG consent decree and the associated costs; and

•

efforts to position our power generation business for future growth and pursuing and executing acquisition, disposition or combination opportunities.

Any or all of our forward-looking statements may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks, uncertainties and other factors, many of which are beyond our control, including those set forth under Part II–Other Information, Item 1A-Risk Factors.

RECENT ACCOUNTING PRONOUNCEMENTS

See Note 1—Accounting Policies to the unaudited condensed consolidated financial statements for a discussion of recently issued accounting pronouncements affecting us.

CRITICAL ACCOUNTING POLICIES

Please read Note 1—Accounting Policies—Goodwill and Other Intangible Assets for further discussion of our policy with respect to goodwill and other intangible assets. Please read “Critical Accounting Policies” beginning on page 74 and page 62, respectively, of Dynegy’s and DHI’s Forms 10-K for a complete description of our critical accounting policies, with respect to which there have been no other material changes since the filing of such Forms 10-K. Please read Note 1—Accounting Policies—Goodwill and Other Intangible Assets for further discussion of our policy with respect to goodwill and other intangible assets.

Item 3—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK—DYNEGY INC. AND DYNEGY HOLDINGS INC.

Please read Item 7A. Quantitative and Qualitative Disclosures About Market Risk beginning on page 81 and page 68, respectively, of Dynegy’s and DHI’s Forms 10-K for a discussion of our exposure to commodity price variability and other market risks, including foreign currency exchange rate risk. Following is a discussion of the more material of these risks and our relative exposures as of June 30, 2007.

Value at Risk (“VaR”). The following table sets forth the aggregate daily VaR of the mark-to-market portion of our risk-management portfolio primarily associated with the GEN segments and the CRM business. The VaR calculation does not include market risks associated with the accrual portion of the risk-management portfolio that is designated as a cash flow hedge or a “normal purchase normal sale”, nor does it include expected future production from our generating assets. Also, an inherent limitation to our using the JP Morgan RiskMetrics ^TM approach to calculate VaR is that options are valued using a linear approximation. With the acquisition of several financially-settled heat rate call-option agreements in the LS Power business combination, the actual change in the fair value of these instruments may differ significantly from the calculated VaR.

As of June 30, 2007, there is a significant increase in VaR due to the above mentioned financially-settled heat rate call-options and our decision to cease designating certain derivative transactions as cash flow hedges, beginning with the second quarter 2007.

Daily and Average VaR for Risk-Management Portfolios

Credit Risk. The following table represents our credit exposure at June 30, 2007 associated with the mark-to-market portion of our risk-management portfolio, on a net basis.

Credit Exposure Summary


	Investment Grade Quality
Type of Business:
Financial Institutions	$	457
Utility and Power Generators		31
Oil and Gas Producers		1

Total	$	489

Interest Rate Risk. We are exposed to fluctuating interest rates related to variable rate financial obligations. As of June 30, 2007 our fixed rate debt instruments, as a percentage of total debt instruments, was approximately 76%. Adjusted for interest rate swaps, net notional fixed rate debt as a percentage of total debt is approximately 71%. Based on sensitivity analysis of the variable rate financial obligations in our debt portfolio as of June 30, 2007, it is estimated that a one percentage point interest rate movement in the average market interest rates (either higher or lower) over the 12 months ended June 30, 2008 would either decrease or increase interest expense by approximately $18 million. Over time, we may seek to reduce or increase the percentage of fixed rate financial obligations in our debt portfolio through the use of swaps or other financial instruments.

Derivative Contracts. The notional financial contract amounts associated with our interest rate contracts were as follows at June 30, 2007 and December 31, 2006, respectively:

Absolute Notional Contract Amounts


	June 30, 2007		December 31, 2006
Fair Value Hedge Interest Rate Swaps (In Millions of U.S. Dollars)	$	525	$	525
Fixed Interest Rate Received on Swaps (Percent)		4.33		4.33
Interest Rate Risk-Management Contract (In Millions of U.S. Dollars)	$	526	$	306
Fixed Interest Rate Paid (Percent)		5.30		5.29
Interest Rate Risk-Management Contract (In Millions of U.S. Dollars)	$	281	$	281
Fixed Interest Rate Received (Percent)		5.23		5.23

Item 4—CONTROLS AND PROCEDURES—DYNEGY INC. AND DYNEGY HOLDINGS INC.

DHI is not subject to the disclosure requirements promulgated under Section 404 of the Sarbanes-Oxley Act of 2002 with respect to its internal control over financial reporting until DHI files its 2007 Form 10-K. Nevertheless, because DHI comprises a significant part of Dynegy as a consolidated enterprise, DHI’s internal control over financial reporting has been reviewed in connection with Dynegy’s compliance with Section 404 of the Sarbanes-Oxley Act.

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of Dynegy’s and DHI’s management, including their Chief Executive Officer and their Chief Financial Officer, of the effectiveness of the design and operation of the consolidated enterprise’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). This evaluation included consideration of the various processes carried out under the direction of Dynegy’s disclosure committee in an effort to ensure that information required to be disclosed in the consolidated enterprise’s SEC reports is recorded, processed, summarized and reported within the time periods specified by the SEC. This evaluation also considered the work completed as of the end of the second quarter 2007 relating to Dynegy’s compliance with Section 404 of the Sarbanes-Oxley Act of 2002. Based on this evaluation, Dynegy’s and DHI’s CEO and CFO concluded that Dynegy’s and DHI’s disclosure controls and procedures were effective as of June 30, 2007.

Changes in Internal Controls Over Financial Reporting

There were no changes in the consolidated enterprise’s internal control over financial reporting that have materially affected or are reasonably likely to materially affect the consolidated enterprise’s internal control over financial reporting during the second quarter 2007.

DYNEGY INC. and DYNEGY HOLDINGS INC.

PART II. OTHER INFORMATION

Item 1—LEGAL PROCEEDINGS—DYNEGY INC. AND DYNEGY HOLDINGS INC.

See Note 10—Commitments and Contingencies to the accompanying unaudited condensed consolidated financial statements for discussion of the legal proceedings that we believe could be material to us.

Item 1A—RISK FACTORS—DYNEGY INC. AND DYNEGY HOLDINGS INC.

See Item 1A—Risk Factors on page F-22 and page F-18, respectively, of Dynegy’s and DHI’s Forms 10-K as updated in their respective Forms 10-Q for the quarter ended March 31, 2007 for factors, risks and uncertainties that may affect future results.

If Dynegy issues a material amount of its common stock in the future or certain of its stockholders sell a material amount of Dynegy’s common stock its ability to use federal net operating losses to offset future taxable income may be limited under Section 382 of the Internal Revenue Code. CUSA’s sale of Dynegy’s stock resulted in such a limitation and further future ownership changes, such as any sale by the LS Contributing Entities or their affiliates, may result in additional limitations.

Our ability to utilize previously incurred federal NOLs to offset our future taxable income could be limited due to a recent “ownership change” within the meaning of Section 382 of the Code. In general, an “ownership change” occurs whenever the percentage of the stock of a corporation owned by “5-percent shareholders” (within the meaning of Section 382 of the Code) increases by more than 50 percentage points over the lowest percentage of the stock of such corporation owned by such “5-percent shareholders” at any time over the preceding three years.

CUSA’s sale of Dynegy’s Class A common stock on May 24, 2007 triggered an “ownership change”. The sale of stock resulted in an annual limitation on the utilization of the deferred tax assets attributable to our previously incurred federal NOLs against our total future taxable income; however, the impact is not anticipated to be material.

Any material future ownership changes could result in additional limitations on our utilization of our federal NOLs to offset our future taxable income and our ability to raise additional equity capital may be limited. The magnitude of such limitations and their effect on us depends in part on the market value of Dynegy’s stock at the time of any such ownership change and then-prevailing interest rates, as well as the availability of built-in gains which may reduce any such effects. For accounting purposes, at January 1, 2007, Dynegy’s deferred tax asset attributable to its previously incurred federal NOLs was valued at approximately $243 million.

If our goodwill or amortizable intangible assets become impaired, we may be required to record a significant charge to earnings.

Under GAAP, we review our amortizable intangible assets for impairment when events or changes in circumstances indicate the carrying value may not be recoverable. Goodwill is required to be tested for impairment at least annually. Factors that may be considered a change in circumstances indicating that the carrying value of our goodwill or amortizable intangible assets may not be recoverable include a decline in future cash flows and slower growth rates in the energy industry. We may be required to record a significant charge to earnings in our financial statements during the period in which any impairment of our goodwill or amortizable intangible assets is determined, resulting in an impact on our results of operations.

Item 2—UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS—DYNEGY INC.

Upon vesting of restricted stock awarded by the company to employees, shares are withheld to cover the employees’ withholding taxes. Information on the company’s purchases of equity securities during the quarter follows:


Period	(a) Total Number of Shares Purchased	(b) Average Price Paid per Share	(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
April	384,294	9.67	—	N/A
May	—	—	—	N/A
June	—	—	—	N/A

These were the only repurchases of equity securities made by us during the three months ended June 30, 2007 and occurred in connection with the vesting of all then outstanding restricted stock awards upon closing of the Merger on April 2, 2007. Dynegy does not have a repurchase program.

Item 6—EXHIBITS—DYNEGY INC. AND DYNEGY HOLDINGS INC.

The following documents are included as exhibits to this Form 10-Q:


Exhibit Number		Description
3.1		Amended and Restated Certificate of Incorporation of Dynegy Inc. (formerly named Dynegy Acquisition, Inc.) (incorporated by reference to Exhibit 4.1 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221).

3.2		Amended and Restated Bylaws of Dynegy Inc. (formerly named Dynegy Acquisition, Inc.) (incorporated by reference to Exhibit 4.2 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-139221).

4.1		Third Supplemental Indenture, dated as of May 24, 2007, to that certain Indenture, originally dated as of September 26, 1996, as amended and restated as of March 23, 1998 and again as of March 14, 2001, by and between Dynegy Holdings Inc. and Wilmington Trust Company (as successor to JPMorgan Chase Bank, N.A.), as trustee, as supplemented by that certain First Supplemental Indenture, dated as of July 25, 2003, and that certain Second Supplemental Indenture, dated as of April 12, 2006 (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. filed on May 25, 2007, File No. 333-139221).


Exhibit Number		Description
4.2		Fourth Supplemental Indenture, dated as of May 24, 2007, to that certain Indenture, originally dated as of September 26, 1996, as amended and restated as of March 23, 1998 and again as of March 14, 2001, by and between Dynegy Holdings Inc. and Wilmington Trust Company (as successor to JPMorgan Chase Bank, N.A.), as trustee, as supplemented by that certain First Supplemental Indenture, dated as of July 25, 2003, that certain Second Supplemental Indenture, dated as of April 12, 2006, and that certain Third Supplemental Indenture, dated as of May 24, 2007 (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K of Dynegy Inc. filed on May 25, 2007, File No. 333-139221).

4.3		Registration Rights Agreement, dated as of May 24, 2007, by and among Dynegy Holdings Inc. and the several initial purchasers party thereto (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K of Dynegy Inc. filed on May 25, 2007, File No. 333-139221).

10.1		Purchase and Sale Agreement, dated May 28, 2007, by and between Dynegy Holdings Inc. and EnergyCo., LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on May 31, 2007, File No. 333-139221).

**10.2		Purchase Agreement, dated as of May 17, 2007, by and between Dynegy Holdings Inc. and J.P. Morgan Securities Inc.

10.3		Underwriting Agreement, dated as of May 21, 2007, by and among Goldman, Sachs & Co., Chevron U.S.A. Inc. and Dynegy Inc. (incorporated by reference to Exhibit 1.1 to the Current Report on Form 8-K of Dynegy Inc. filed on May 25, 2007, File No. 333-139221).

10.4		Fifth Amended and Restated Credit Agreement, dated as of April 2, 2007, by and among Dynegy Holdings Inc., as borrower, Dynegy Inc. (formerly named Dynegy Acquisition, Inc.) and Dynegy Inc., as parent guarantors, the other guarantors party thereto, the lenders party thereto and various other parties thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.5		Amendment No. 1, dated as of May 24, 2007, to the Fifth Amended and Restated Credit Agreement, dated as of April 2, 2007, by and among Dynegy Holdings Inc., as borrower, Dynegy Inc. and Dynegy Illinois Inc., as parent guarantors, the other guarantors party thereto, the lenders party thereto and various other parties thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on May 25, 2007, File No. 333-139221).

10.6		Second Amended and Restated Security Agreement, dated April 2, 2007, by and among Dynegy Holdings Inc., as Borrower, the initial grantors party thereto, Wilmington Trust Company, as corporate trustee, and John M. Beeson, Jr., as individual trustee (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.7		First Lien Credit Agreement, dated as of May 4, 2006, by and among LSP Gen Finance Co, LLC, as borrower, and the guarantors, lenders and other parties thereto (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).


Exhibit Number		Description
10.8		Second Lien Credit Agreement, dated as of May 4, 2006, by and among LSP Gen Finance Co, LLC, as borrower, and the guarantors, lenders and other parties thereto (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.9		$500,000,000 Special Letter of Credit Facility Agreement, dated as of May 4, 2006, by and among LSP Gen Finance Co, LLC, as borrower, and the guarantors, lenders and other parties thereto (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.10		$150,000,000 First Lien Letter of Credit Facility Agreement, dated as of August 3, 2006, by and among LSP Gen Finance Co, LLC, as borrower, and the guarantors, lenders and other parties thereto (incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.11		Credit Agreement, dated as of October 7, 2005, by and among LSP-Kendall Energy, LLC, as borrower, and the lenders and other parties thereto (incorporated by reference to Exhibit 10.7 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.12		Amended and Restated First Lien Credit Agreement, dated as of May 5, 2006, by and among Ontelaunee Power Operating Company, LLC, as borrower, and the lenders and other parties thereto (incorporated by reference to Exhibit 10.8 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.13		Second Lien Credit Agreement, dated as of May 5, 2006, by and among Ontelaunee Power Operating Company, LLC, as borrower, and the lenders and other parties thereto (incorporated by reference to Exhibit 10.9 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.14		Credit Agreement, dated as of March 29, 2007, by and among Plum Point Energy Associates, LLC, as borrower, and the lenders and other parties thereto (incorporated by reference to Exhibit 10.10 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.15		Collateral Agency and Intercreditor Agreement, dated as of March 29, 2007, by and among Plum Point Energy Associates, LLC, as borrower, PPEA Holding Company, LLC, as Pledgor, The Bank of New York, as collateral agent, The Royal Bank of Scotland, as Administrative Agent, AMBAC Assurance Corporation, as Loan Insurer (as defined below), and the other parties thereto (incorporated by reference to Exhibit 10.11 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.16		Loan Agreement, dated as of April 1, 2006, by and between the City of Osceola, Arkansas and Plum Point Energy Associates, LLC (incorporated by reference to Exhibit 10.12 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.17		Trust Indenture, dated as of April 1, 2006, by and between the City of Osceola, Arkansas and Regions Bank, as trustee (incorporated by reference to Exhibit 10.13 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).


Exhibit Number		Description
10.18		Amended and Restated Limited Liability Company Agreement of DLS Power Holdings, LLC, dated April 2, 2007, by and between LS Power Associates, L.P. and Dynegy Inc. (formerly named Dynegy Acquisition, Inc.) (incorporated by reference to Exhibit 10.14 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.19		Limited Liability Company Agreement of DLS Power Development Company, LLC, dated April 2, 2007, by and between LS Power Associates, L.P. and Dynegy Inc. (formerly named Dynegy Acquisition, Inc.) (incorporated by reference to Exhibit 10.15 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.20		Third Amendment to the Dynegy Inc. Executive Severance Pay Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.17 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.21		Second Amendment to Dynegy Inc. Severance Pay Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.19 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.22		Ninth Amendment to the Dynegy Inc. Retirement Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.29 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.23		Eleventh Amendment to the Dynegy Inc. 401(k) Savings Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.30 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.24		Sixth Amendment to the Dynegy Inc. Comprehensive Welfare Benefits Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.31 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.25		First Amendment to the Dynegy Inc. Incentive Compensation Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.32 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.26		First Amendment to the Dynegy Inc. 1999 Long Term Incentive Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.33 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.27		Second Amendment to the Dynegy Inc. 2000 Long Term Incentive Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.34 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.28		First Amendment to the Dynegy Inc. 2001 Non-Executive Stock Incentive Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.35 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.29		Second Amendment to the Dynegy Inc. 2002 Long Term Incentive Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.36 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).


Exhibit Number		Description
10.30		Third Amendment to the Dynegy Inc. Deferred Compensation Plan for Certain Directors, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.37 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.31		Amendment to the Dynegy Inc. Deferred Compensation Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.38 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.32		Sixth Amendment to the Dynegy Midwest Generation, Inc. Retirement Income Plan for Employees Covered Under a Collective Bargaining Agreement, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.39 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.33		Eighth Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.40 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.34		Eighth Amendment to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan for Employees Covered Under a Collective Bargaining Agreement, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.41 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.35		Seventh Amendment to the Dynegy Northeast Generation, Inc. Retirement Income Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.42 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.36		Fifth Amendment to the Dynegy Northeast Generation, Inc. Savings Incentive Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.43 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.37		Eighth Amendment to the Extant, Inc. 401(k) Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.44 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.38		Amendment to Trust Agreement – DMG 401(k) Savings Plan (Vanguard), dated as of April 2, 2007 (incorporated by reference to Exhibit 10.51 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.39		Amendment to Trust Agreement – Dynegy Inc. 401(k) Savings Plan (Vanguard), dated as of April 2, 2007 (incorporated by reference to Exhibit 10.53 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.40		Amendment to Dynegy Inc. Deferred Compensation Plan Trust Agreement (Vanguard), dated as of April 2, 2007 (incorporated by reference to Exhibit 10.54 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).

10.41		Amendment to Master Trust Agreement (Vanguard Fiduciary Trust Company), dated as of April 2, 2007 (incorporated by reference to Exhibit 10.55 to the Current Report on Form 8-K of Dynegy Inc. filed on April 6, 2007, File No. 333-139221).


Exhibit Number		Description
**31.1		Chief Executive Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

**31.1(a)		Chief Executive Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

**31.2		Chief Financial Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

**31.2(a)		Chief Financial Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

†32.1		Chief Executive Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

†32.1(a)		Chief Executive Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

†32.2		Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

†32.2(a)		Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.1		Combined Financial Statements of the Power Generation Business of LS Power Development, LLC and Affiliates as of December 31, 2006 and 2005 and for each of the two years in the period ended December 31, 2006 (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K/A of Dynegy Inc. filed on May 2, 2007, File No. 333-139221).

99.2		Dynegy Illinois Inc. (formerly named Dynegy Inc.) Unaudited Pro Forma Condensed Combined Financial Information (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K/A of Dynegy Inc. filed on May 2, 2007, File No. 333-139221).

**	Filed herewith.

†

Pursuant to Securities and Exchange Commission Release No. 33-8238, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or the Exchange Act, or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act.

DYNEGY INC. and DYNEGY HOLDINGS INC.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	DYNEGY INC.

Date: August 9, 2007	By:	/s/ HOLLI C. NICHOLS
		Holli C. Nichols
		Executive Vice President and Chief Financial Officer
		(Duly Authorized Officer and Principal Financial Officer)


	DYNEGY HOLDINGS INC.

Date: August 9, 2007	By:	/s/ HOLLI C. NICHOLS
		Holli C. Nichols
		Executive Vice President and Chief Financial Officer
		(Duly Authorized Officer and Principal Financial Officer)